エメラの年次報告

/s/ Ernst & Young LLP

Halifax, Canada

Chartered Professional Accountants

February 23, 2026

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM

40-F

☐

☒

ANNUAL

REPORT

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

For the fiscal year ended

December 31, 2025

Commission File Number

001-42631

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)

EUSHI Finance, Inc.

37 Route 236

Kittery Properties Suite 101

Kittery

03904

Telephone: (

902

)

233-4084

(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:

Title of each class

Trading symbol(s)

Name of each exchange on which registered

Common Shares, no par value

EMA

New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of

the Act:

None

Securities for which there is a reporting obligation pursuant to Section 15(d) of

the Act:

None

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

☒

Annual information form

☒

Audited annual financial statements

Indicate the number of outstanding shares of each of the issuer’s classes of

capital or common stock as of the close of the period covered by the annual report:

301,754,258

Common Shares

6,000,000

Series A 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 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 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 its financial statements

in accordance with U.S. GAAP,

indicate by check

mark if the registrant has elected not to use the extended transition period for complying

with any new or revised financial

accounting standards† provided pursuant to Section 13(a) of the Exchange

Act.

☐

† The term “new or revised financial accounting standard” refers to any update

issued by the Financial Accounting

Standards Board to its Accounting Standards Codification after April 5, 2012.

Indicate by check mark whether the registrant has filed a report on and

attestation to its management’s assessment of

the

effectiveness of its internal control over financial reporting under

Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.

7262(b)) by the registered public accounting firm that prepared

or issued its audit report.

☐

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 Emera Incorporated (the “Registrant”) is a Canadian issuer that is permitted, under the multijurisdictional disclosure

pursuant to § 240.10D-1(b).

☐

EXPLANATORY

NOTE

system adopted in the United States, to prepare its annual report pursuant to

Section 13 of the Securities Exchange Act of

1934, as amended (the “Exchange Act”), in accordance with disclosure requirements

in effect in Canada that differ from

those of the United States. The Registrant is a “foreign private issuer” as defined

in Rule 3b-4 under the Exchange Act

and in Rule 405 under the Securities Act of 1933, as amended. Equity securities of the

Registrant are accordingly exempt

from Sections 14(a), 14(b), 14(c) and 14(f) of the Exchange Act pursuant

to Rule 3a12-3.

Differences in United States and Canadian Reporting Practices

The Registrant is permitted, under the multijurisdictional disclosure system adopted

by the United States, to prepare

reports it files with the United States Securities and Exchange Commission (the

“Commission”) in accordance with

Canadian disclosure requirements, which are different from

those of the United States. The Registrant currently prepares

its financial statements, including those which are filed as exhibits to this Form

40-F,

in accordance with U.S. generally

accepted accounting principles.

Principal Documents

The following documents, filed as Exhibits 99.1 through 99.3 hereto, are hereby

incorporated by reference into this Form

40-F:

(a)

Annual Information Form dated February 23, 2026 for the fiscal year ended

December 31, 2025 (filed as Exhibit

99.1 hereto) (the “Annual Information Form”);

(b)

Management’s Discussion and Analysis

dated February 23, 2026 for the year ended December 31, 2025 (filed

Exhibit 99.2 hereto) (the “MD&A”); and

(c)

Audited Consolidated Financial Statements as at and for the years ended

December 31, 2025 and December 31,

2024 (filed as Exhibit 99.3 hereto) (the “Financial Statements”).

Tax Matters

Purchasing, holding, or disposing of securities of the Registrant may

have tax consequences under the laws of the United

States and Canada that are not described in this Form 40-

Certifications and Disclosure Regarding Controls

and Procedures

(a)

Certifications regarding controls and procedures. See Exhibits 99.5

through 99.8.

(b)

Evaluation of disclosure controls and procedures. As of December 31, 2025, 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 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

(i) recorded, processed, summarized and reported within the time periods

specified in the Commission’s rules

and forms and (ii) accumulated and communicated to the Registrant’s

management, including its CEO and CFO,

as appropriate, to allow timely decisions regarding required disclosure.

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

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, 2025 and concluded that the Registrant’s

internal control over financial reporting is effective as at December

31, 2025.

(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

due

to a transition period established by rules of the Commission for

newly public companies.

(e)

Changes in internal control over financial reporting. The information provided

under the heading “Disclosure

and Internal Controls—Change in ICFR” contained in the Registrant’s

MD&A is incorporated by reference

herein.

Notices Pursuant to Regulation BTR

Not applicable.

Identification of the Audit Committee

The Registrant has a separately designated standing audit committee established

in accordance with section 3(a)(58)(A) of

the Exchange Act. The members of the audit committee are: Isabelle Courville,

Paula Y.

Gold-Williams, Kent M. Harvey,

B. Lynn Loewen, Ian E. Robertson

and Carla M. Tully,

each of whom is “independent” as such term is defined in the

rules of the New York

Stock Exchange (the “NYSE”).

Audit Committee Financial Expert

The Registrant’s board of directors

(the “Board”) has determined that six audit committee financial experts serve on

its

audit committee. The audit committee financial experts are Isabelle Courville, Paula

Gold-Williams, Kent M. Harvey,

B. Lynn Loewen, Ian E. Robertson

and Carla M. Tully.

Information concerning the relevant experience of Isabelle

Courville, 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. 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 (the “Code”) was revised and became effective

on January 1, 2026 and applies to all

directors, officers and employees of the Registrant, including

the CEO and CFO. The revisions to the Code included: (i)

the addition of guidance regarding the responsible use of business expenses,

travel and entertainment, including

strengthened expectations for ethical conduct and accountability; (ii) enhanced

guidance on the responsible use of

artificial intelligence tools, including an expectation

to verify the accuracy of AI-generated information used in business

communications and work product; and (iii) an update to the Code’s

waiver provisions to clarify that any waiver for

executive officers or directors may be granted only by

the Company’s Board of Directors (or a

Board committee) and will

be disclosed to the extent required by applicable law,

regulation or stock exchange requirement. Other administrative

updates were made to the Code that were not substantive.

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/code-of-conduct. Any amendments or waivers to the Code with respect to

any of the

directors, officers and employees covered by it will be posted

promptly on the Registrant’s website. Information

contained

or otherwise accessed through the Registrant’s

website or any other website, other than those documents filed as exhibits

hereto or otherwise specifically referred to herein, does not form part of

this Form 40-F,

and any reference to the

Registrant’s website herein is as an inactive

textual reference only.

The Code was furnished to the Commission on January 12, 2026 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 is incorporated by

reference herein. The Registrant’s

Audit Committee approved all of the Audit-Related and Tax

services provided by Ernst

& Young

LLP in 2025, 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.

The Registrant hereby affirms that Ernst & Young

LLP (PCAOB ID:

1263

) delivered an audit opinion relating to the

Registrant’s Financial Statements

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 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 Financial Statements, are 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.

NYSE CORPORATE

GOVERNANCE

As a foreign private issuer, the Registrant is not required

to comply with most of the NYSE corporate governance

requirements to which the Registrant would be subject if it were a U.S. domestic

issuer. The Registrant’s

governance

practices only significantly differ from those required of

U.S. domestic issuers as described below.

Equity Compensation Plans.

The NYSE rules for U.S. domestic issuers require shareholder approval of

all equity

compensation plans (as defined in the NYSE rules) regardless of whether

new issuances, treasury shares or shares that the

issuer has purchased in the open market are used. The Toronto

Stock Exchange (“TSX”) rules require shareholder

approval of share compensation arrangements involving new issuances of

shares, and of certain amendments to such

arrangements, but do not require such approval if the compensation arrangements involve only shares purchased in the Share Issuances.

open market.

The NYSE rules for U.S. domestic issuers also require shareholder approval

of certain transactions or

series of related transactions that result in the issuance of common shares, or securities

convertible into or exercisable for

common shares, that have, or will have upon issuance, voting power equal to or in excess of

20% of the voting power

outstanding prior to the transaction or if the issuance of common shares, or securities

convertible into or exercisable for

common shares, are, or will be upon issuance, equal to or in excess of 20% of the number of

common shares outstanding

prior to the transaction. The TSX rules require shareholder approval of

acquisition transactions resulting in dilution of

listed securities (including upon conversion or exchange of other

securities) in excess of 25%. Shareholder approval is

also required for private placements (i) for an aggregate number

of listed securities (including upon conversion or

exchange of other securities) greater than 25% of the number of securities outstanding

prior to the transaction, at a price

less than the “market price” (as defined in the TSX rules), (ii) that are to insiders and, during

a six month period, exceed

10% of the number of listed securities (including upon conversion or

exchange) outstanding at the beginning of that

period, or (iii) that will result in a new holding by a security holder or group of

securityholders of more than 20% of the

outstanding voting securities of the issuer.

The TSX also has broad general discretion to require shareholder approval

connection with any issuances of listed securities.

The Registrant intends to comply with the TSX rules for equity compensation

plans and share issuances as described

above, in lieu of the corresponding NYSE rules.

UNDERTAKING

AND CONSENT TO SERVICE OF PROCESS

Undertaking

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 registered pursuant to Form 40-F; the securities in relation

to which the obligation to file an annual report on

Form 40-F arises; or transactions in said securities.

Consent to Service of Process

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.

EXHIBIT INDEX

Exhibit Number

Description

97.1

Compensation Recovery Policy

99.1

2025 Annual Information Form dated February 23, 2026 for the fiscal year

ended December 31,

2025

99.2

Management’s Discussion and Analysis

dated February 23, 2026 for the year ended December

31, 2025

99.3

Audited Consolidated Financial Statements as at and for the years ended

December 31, 2025 and

December 31, 2024

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,

2026) (incorporated by reference

to Emera Incorporated’s Form 6-K,

furnished to the Commission on January 12, 2026)

101

Interactive Data File (formatted as Inline XBRL)

104

Cover Page Interactive Data File (formatted as Inline XBRL and contained

in Exhibit 101)

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.

Date: February 23, 2026

EMERA INCORPORATED

By:

/s/ Scott C. Balfour

Name:

Scott C. Balfour

Title:

President & Chief

Executive Officer

EX-97.1 2 d845370dex971.htm EX-97.1 EX-97.1

Exhibit 97.1

LOGO

EMERA

Executive Incentive Compensation Recoupment Policy

Purpose of the Policy

This Executive Incentive Compensation Recoupment Policy (this “Policy”) has been adopted by Emera Incorporated (“Emera”) as of the Effective Date (as defined below) to enhance its alignment with good compensation governance practices and to help Emera manage its compensation-related risk. This Policy applies to any individual who is or was an Executive Officer (as defined below) at the relevant time. Upon the occurrence of a Restatement Recoupment Event or a Misconduct Recoupment Event (each as defined below), certain Incentive Compensation (as defined below) received by an Executive Officer will be clawed back, on and subject to the terms provided for in this Policy.

Definitions

In this Policy the following capitalized terms have the meanings set out below:

“Applicable Rules” means any laws, regulations and rules of any stock exchange applicable to Emera or an Executive Officer, including the U.S. Stock Exchange Rules (as defined below).

“Board” means the board of directors of Emera.

“Effective Date” means May 22, 2025.

“Emera Group” means Emera and all entities in respect of which Emera is the majority shareholder, whether directly or indirectly.

“Erroneously Awarded Compensation” means, in connection with a Restatement, the amount of Incentive Compensation received by an Executive Officer that exceeds the amount of Incentive Compensation that otherwise would have been received by such Executive Officer had such Incentive Compensation been determined based on the restated amounts after giving effect to such Restatement, without regard to any taxes paid by such Executive Officer.

“Exchange Act” means the United States Securities Exchange Act of 1934, as amended.

“Executive Officer” means Emera’s president, principal financial officer, principal accounting officer (or if there is no such accounting officer, the controller), any vice-president of Emera in charge of a principal business unit, division or function (such as sales, administration or finance), any other officer who performs a significant policy-making function or any other person who performs similar significant policy-making functions for Emera, as identified in Emera’s most recently filed annual report on Form 40-F (or other applicable form), or any vice president or other executive officer of an affiliate of Emera as determined by the Board or the MRC Committee from time to time. For clarity, and without limiting the foregoing, executive officers of Emera’s parent(s) or subsidiaries are deemed “Executive Officers” if they perform such policy making functions for Emera.

“Financial Reporting Measure” means measures that are determined and presented in accordance with the accounting principles used in preparing Emera’s financial statements, and any measures that are derived wholly or in part from such measures.

“Incentive Compensation” means that portion of an Executive Officer’s compensation from the Emera Group that is related to achieving financial or other performance goals under a variable short- or long-

term incentive compensation plan or is otherwise granted, earned, or vested based wholly or in part upon the attainment of a Financial Reporting Measure.

“Misconduct” means (i) fraud, (ii) intentional and material non-compliance with applicable laws or Emera’s Standards of Business Conduct, and (iii) any failure to report or take action to stop the Misconduct of another employee the Executive Officer had actual knowledge of or was willfully blind about.

“Misconduct Recoupment Amount” means the portion of an Executive Officer’s Incentive Compensation relating to the year(s) in which such Executive Officer engaged in Misconduct and that the Board, acting reasonably, determines should be subject to recoupment pursuant to a Misconduct Recoupment Event.

“MRC Committee” means the Management Resources and Compensation Committee of the Board.

“Restatement” means any accounting restatement due to Emera’s material non-compliance with any applicable financial reporting requirement under United States federal securities laws, including any required accounting restatement to correct a material error in Emera’s previously-issued financial statements, or to avoid a material misstatement if the error were corrected in the current period or left uncorrected in the current period. For clarity, a restatement due to a change in applicable accounting rules, standards or interpretations, a change in segment designations or the discontinuance of an operation shall not require the application of this Policy.

“Restatement Date” means the date upon which Emera is required to prepare a Restatement (such date as determined by Rule 10D-1(b)(1)(ii) under the Exchange Act and the applicable U.S. Stock Exchange Rules).

“SEC” means the United States Securities and Exchange Commission.

“U.S. Stock Exchange” means the New York Stock Exchange and/or any other U.S. national securities exchange on which Emera’s securities are listed.

“U.S. Stock Exchange Rules” means Section 303A.14 of the New York Stock Exchange Listed Company Manual and/or the listing standards of any other U.S. national securities exchange(s) on which Emera’s securities are listed to implement Rule 10D-1 under the Exchange Act.

Application

This Policy applies to all persons who are or become Executive Officers on or after the Effective Date and applies to all Incentive Compensation awarded or granted to, or vested or earned by, an Executive Officer on or after the Effective Date.

In accordance with the procedure set out below, and on the recommendation of the MRC Committee, and in all events, subject to Applicable Rules, the Board may determine and recover a Misconduct Recoupment Amount in the event of a Misconduct Recoupment Event and the Board will determine and recover any Erroneously Awarded Compensation in the event of a Restatement Recoupment Event.

Restatement Recoupment Event

In the event Emera is required to prepare a Restatement, the Board will review all Incentive Compensation received by Executive Officers (a) after beginning service as an Executive Officer, (b) who served as an Executive Officer at any time during the performance period for such Incentive Compensation, (c) during the three completed fiscal years immediately preceding the applicable Restatement Date (as well as during any transition period specified in Rule 10D-1(b)(1)(i)(D) under the Exchange Act and the applicable U.S. Stock Exchange Rules), (d) while Emera had a class of securities listed on a U.S. Stock Exchange, and (e) after the U.S. Stock Exchange Rules became effective. Incentive Compensation is deemed “received” in the fiscal period during which the Financial Reporting Measure specified in the Incentive Compensation is attained, even if the payment or grant of Incentive Compensation occurs after the end of that period. If the Board determines that one or more Executive Officers have received any Erroneously Awarded Compensation in connection with such Restatement, Emera shall, reasonably promptly after the Restatement Date, seek recoupment from all such Executive Officers of all such Erroneously Awarded Compensation (a “Restatement Recoupment Event”), subject to the exceptions set forth below under “—Restatement Recoupment Exceptions”.

Calculation of Erroneously Awarded Compensation

For Incentive Compensation based on stock price or total shareholder return, where the amount of Erroneously Awarded Compensation is not subject to mathematical recalculation directly from the information in a Restatement: (i) the amount of Erroneously Awarded Compensation must be based on a reasonable estimate of the effect of the Restatement on the stock price or total shareholder return upon which the Incentive Compensation was received; and (ii) Emera must maintain documentation of the determination of that reasonable estimate and provide such documentation to the applicable U.S. Stock Exchange. Reference is further made to Rule 10D-1(b)(1)(iii) under the Exchange Act and the applicable U.S. Stock Exchange Rules for calculation of Erroneously Awarded Compensation.

Restatement Recoupment Exceptions

Any Erroneously Awarded Compensation must be recovered as provided in this Policy unless the MRC Committee determines that any of the impracticality exceptions set forth in Rule 10D- 1(b)(1)(iv) under the Exchange Act and/or the U.S. Stock Exchange Rules are available, as set forth below:

(a)

The direct expense paid to a third party to assist in enforcing this Policy would exceed the amount of Erroneously Awarded Compensation to be recovered. Before concluding that it would be impracticable to recover any amount of Erroneously Awarded Compensation pursuant to this clause (a), Emera must make a reasonable attempt to recover such Erroneously Awarded Compensation, document such reasonable attempt(s) to recover and provide that documentation to the U.S. Stock Exchange.

(b)

Recovery would violate home country law where that law was adopted prior to November 28, 2022. Before concluding that it would be impracticable to recover any amount of Erroneously Awarded Compensation pursuant to this clause (b), Emera must obtain an opinion of home country counsel, acceptable to the U.S. Stock Exchange, that recovery would result in such a violation, and must provide such opinion to the U.S. Stock Exchange.

(c)

Recovery would likely cause an otherwise tax-qualified retirement plan, under which benefits are broadly available to employees of Emera, to fail to meet the requirements of 26 U.S.C. 401(a)(13) or 26 U.S.C. 411(a) and regulations thereunder.

The obligation to recover Erroneously Awarded Compensation is not dependent on whether or when the restated financial statements in connection with the Restatement have been filed.

Recoupment of Erroneously Awarded Compensation due to a Restatement will be made on a “no fault” basis, without regard to whether any Executive Officer is responsible for the noncompliance that resulted in the Restatement.

Emera shall not indemnify any Executive Officer against the loss of any Erroneously Awarded Compensation.

Misconduct Recoupment Event

A “Misconduct Recoupment Event” occurs if:

An Executive Officer engages in Misconduct (including intentional and material non-compliance with Emera’s Standards of Business Conduct) or in any act or omission that may entitle an employer to terminate the Executive Officer for cause under applicable law, regardless of whether or not the Executive Officer was terminated for cause; and

The MRC Committee determines and makes a recommendation to the Board that it is appropriate to recoup a Misconduct Recoupment Amount from that Executive Officer.

MRC Committee Discretion

In determining whether it is appropriate that an Executive Officer’s Incentive Compensation is subject to recoupment under this Policy and, if so, the Misconduct Recoupment Amount, the MRC Committee may, acting reasonably, take into account any factors it deems relevant, including (i) the individual’s position and degree of responsibility for the Misconduct, (ii) the availability of other remedies to Emera and the Emera Group, (iii) any actual or potential penalties or punishments which regulators or third parties may impose on the Executive Officer or the Emera Group, (iv) the cost and likely outcome of any potential litigation relating to the Misconduct, and whether recoupment may prejudice any other interests of the Emera Group, including any of their respective interests in any related proceeding or investigation, and (v) the extent and seriousness of the Misconduct that resulted in or contributed to a Misconduct Recoupment Event. Following the exercise of its discretion in accordance with this paragraph, the MRC Committee will make recommendations to the Board on actions, if any, to be taken.

Due Process

An Executive Officer whose Incentive Compensation is subject to a Misconduct Recoupment Event under this Policy will be provided with written notice of the intention to recoup amounts under this Policy and the reasons therefor and the opportunity to be heard (which may be in-person, by telephone or in writing, as determined by the Board or a committee thereof). All determinations by the Board or the MRC Committee with respect to a Misconduct Recoupment Event shall be final and binding on all interested parties.

Recoupment Process

The Board has full discretion to determine the method for recovering any Erroneously Awarded Compensation or Misconduct Recoupment Amount (collectively, a “Recoupment Amount”) from an Executive Officer, which may include the following:

to the extent that the Recoupment Amount has not been paid, transferred or otherwise made available to the Executive Officer, cancel, or require the Executive Officer to forfeit, the receipt or payment of all or part of such Recoupment Amount;

to the extent that the Recoupment Amount has been paid, transferred or otherwise made available to the Executive Officer, require, by written demand, the Executive Officer to reimburse Emera for all or part of such Recoupment Amount (which, in the case of options awarded in respect of the year(s) subject to the Restatement which have been exercised by the Executive Officer, means the amount by which the fair market value of a common share of Emera on the date of exercise or settlement exceeded the exercise price for the option); and

iii

to the extent the Recoupment Amount is not immediately recovered upon demand from the Executive Officer, whether by reimbursement, forfeiture and/or cancellation, deduct (to the full extent permitted by Applicable Rules) the Recoupment Amount, or any unrecovered portion thereof, from the wages (including but not limited to base salary and bonus) and/or any other Incentive Compensation whether or not referable to the financial years subject to a Restatement owing, awarded or payable by Emera to the Executive Officer or withhold, forfeit and/or cancel any Incentive Compensation to compensate for the Recoupment Amount or any unrecovered portion thereof, and to bring any other actions against the Executive Officer which they may deem necessary or advisable to recover all or part of the Recoupment Amount.

Indemnification of the Board

Any members of the Board who assist in the administration of this Policy will not be personally liable for any action, determination or interpretation made with respect to this Policy and will be fully indemnified by Emera to the fullest extent permitted under applicable law and Emera policy with respect to any such action, determination or interpretation. The foregoing sentence will not limit any other rights to indemnification of the members of the Board under applicable law or Emera policy.

Further Reference to Applicable SEC and U.S. Stock Exchange Rules

This Policy shall be qualified by reference to, is designed to comply with, and will be interpreted consistent with applicable SEC rules (including, without limitation, Section 10D of the Exchange Act and Rule 10D-1 under the Exchange Act) and the U.S. Stock Exchange Rules.

Applicability

Each document setting forth the terms and conditions of any Incentive Compensation granted or paid to an Executive Officer will, and will be deemed to, include a provision incorporating this Policy or the requirements of this Policy.

Other Recovery Obligations

To the extent that the application of this Policy would provide for recovery of Incentive Compensation that Emera already recovered pursuant to Section 304 of the Sarbanes-Oxley Act or other recovery obligations, the amount already recovered from the relevant Executive Officer will be credited to the required recovery under this Policy.

Filing with the SEC

This Policy and any amendments thereto shall be filed with the SEC as an exhibit to Emera’s annual report on Form 40-F (or other applicable form) beginning with the first report as specified under the U.S. Stock Exchange Rules.

Interpretation; Amendment

The Board shall have full and final authority to make all determinations under this Policy with respect to any Recoupment Amount, including, without limitation, whether this Policy applies and if so, the amount of compensation to be repaid or forfeited by an Executive Officer. All determinations and decisions made by the Board pursuant to the provisions of this Policy shall be final, conclusive and binding on all parties.

The Board may amend or terminate this Policy from time to time in its sole and absolute discretion and shall amend this Policy as it deems necessary to comply with the U.S. Stock Exchange Rules and all other Applicable Rules.

Severability

The provisions in this Policy are intended to be applied to the fullest extent of the law. To the extent that any provision of this Policy is found to be unenforceable or invalid under any applicable law, such provision shall be applied to the maximum extent permitted and shall automatically be deemed amended in a manner consistent with its objectives to the extent necessary to conform to any limitations required under applicable law.

Successors

This Policy is binding and enforceable against all Executive Officers and their beneficiaries, heirs, executors, administrators or other legal representatives.

This Policy supersedes and replaces the Executive Incentive Compensation Recoupment Policy previously adopted by the Board effective as of January 1, 2014.

General Rules

Except as otherwise permitted under Applicable Rules, an action to recover a Recoupment Amount must be brought within three (3) years following the Restatement Date. Recoupment under this Policy will be initiated by Emera at the request of the Board, and all amounts recoverable or payable hereunder shall be paid to Emera or as directed by the Board.

The remedies specified in this Policy shall not be exclusive and shall be in addition to any other right, action or remedy available to Emera Group against the individual under Applicable Rules, including termination of employment for cause.

ADOPTED by the Board of Directors of Emera Incorporated effective April 23, 2025.

EX-99.1 3 d845370dex991.htm EX-99.1 EX-99.1

Exhibit 99.1

LOGO

Emera Incorporated

Annual Information Form

For the year ended December 31, 2025

February 23, 2026

ANNUAL INFORMATION FORM

For the year ended December 31, 2025

Dated: February 23, 2026

TABLE OF CONTENTS


PRESENTATION OF INFORMATION			4

CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION			4

CORPORATE STRUCTURE			6
Name and Incorporation			6
Intercorporate Relationships			6

INTRODUCTION			6

DESCRIPTION OF THE BUSINESS			7
Business Segments			7
Florida Electric Utility			7
Canadian Electric Utilities			11
Gas Utilities and Infrastructure			13
Other Electric Utilities			16
Other			18

GENERAL DEVELOPMENT OF THE BUSINESS			19
Florida Electric Utility			19
Canadian Electric Utilities			20
Gas Utilities and Infrastructure			24
Other Electric Utilities			25
Other			26
Financing Activity			27

RISK FACTORS			30

CAPITAL STRUCTURE			30
Common Shares			30
Emera First Preferred Shares			30
Emera Second Preferred Shares			31
Share Ownership Restrictions			31

CREDIT RATINGS			32

DIVIDENDS			33

MARKET FOR SECURITIES			34
Trading Price and Volume			34
ATM Program			34

DIRECTORS AND OFFICERS			35
Directors			35
Officers			37

AUDIT COMMITTEE			38
Audit and Non-Audit Services Pre-Approval Process			40
Auditors’ Fees			41


Emera Incorporated – 2025 Annual Information Form		2



CERTAIN PROCEEDINGS		41

CONFLICTS OF INTEREST		42

LEGAL PROCEEDINGS AND REGULATORY ACTIONS		42

NO INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS		42

MATERIAL CONTRACTS		42

TRANSFER AGENT AND REGISTRAR		42

EXPERTS		42

ADDITIONAL INFORMATION		43

APPENDIX “A” - DEFINITIONS OF CERTAIN TERMS		44

APPENDIX “B” – SUMMARY OF TERMS AND CONDITIONS OF AUTHORIZED SERIES OF FIRST PREFERRED SHARES		49

APPENDIX “C” - MONTHLY TRADING VOLUME AND HIGH AND LOW PRICE FOR EMERA’S COMMON AND PREFFERED SHARES IN 2025		52

APPENDIX “D” - EMERA INCORPORATED AUDIT COMMITTEE CHARTER		54


Emera Incorporated – 2025 Annual Information Form		3

PRESENTATION OF INFORMATION

Unless otherwise noted, the information contained in this AIF is given at or for the year ended December 31, 2025. 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 and on EDGAR at www.sec.gov.

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 and on EDGAR at www.sec.gov.

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”), including the United States Private Securities Litigation Reform Act of 1995. 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 with respect to the Company’s expectations regarding future growth, results of operations, performance, earnings, capital investment, sales volumes, recovery of costs, timing of regulatory decisions,, the expected timing and outcome of the pending sale of NMGC, the expected impact of the Cybersecurity Incident (as defined herein) on the Company’s financial position and results of operations, information technology (“IT”) systems restoration, insurance recoveries, and business continuity processes as well as other matters relating to a cybersecurity incident, including business prospects and opportunities. The forward-looking information reflects management’s current beliefs and is based on information currently available to Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the time(s) at which, such events, performance or results will be achieved. All such forward-looking information in this AIF is provided pursuant to safe harbour provisions contained in applicable securities laws.

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


Emera Incorporated – 2025 Annual Information Form		4

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

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

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; system 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; potential impacts of trade disputes and tariffs; estimated energy consumption rates; maintenance of adequate insurance coverage and receipt of proceeds; changes in customer energy usage patterns; developments in technology that could impact demand for electricity; climate risk; weather risk, including higher frequency and severity of weather events; risk of wildfires; unanticipated maintenance and other expenditures; 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; risks and costs associated with the failure of IT infrastructure and cybersecurity incidents, including IT systems restoration and business continuity processes; uncertainties associated with infectious diseases, pandemics and similar public health threats; risks associated with health and safety; market energy sales prices; labour relations; and availability of labour and management resources.

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


Emera Incorporated – 2025 Annual Information Form		5

CORPORATE STRUCTURE

Name and Incorporation

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

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, 2025.


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

INTRODUCTION

Emera (TSX/NYSE: 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, Canada.

Emera’s business strategy is centred on continued investment in its regulated utilities, combined with a focus on operational excellence and efficiency, to safely and reliably deliver energy to its 2.7 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 2025, Emera’s regulated cost-of-service utilities in Florida accounted for 67 per cent of average consolidated rate base, with Atlantic Canada comprising 25 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 2026 through 2030 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 proceeds from the anticipated close of the NMGC transaction. Generally, Emera’s equity requirements are expected


Emera Incorporated – 2025 Annual Information Form		6

to be funded through the issuance of hybrid securities, 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 19 consecutive years and has provided annual dividend growth guidance of one to two per cent. Emera anticipates adjusted EPS growth of five to seven per cent through 2030, using 2024 as the base year, which will support continued reduction in the ratio of dividend payout to adjusted net income over time. 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 and on EDGAR at www.sec.gov.

DESCRIPTION OF THE BUSINESS

Business Segments

Emera’s reportable segments are:

•

Florida Electric Utility, which consists of TEC;

•

Canadian Electric Utilities, which includes NSPI, an equity interest in NSPML (100 per cent) and an indirect voting equity interest in Wasoqonatl Transmission Incorporated (50 per cent);

•

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

•

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

•

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

Emera and its subsidiaries had 7,812 employees as at December 31, 2025, approximately 30 per cent of whom are unionized.

Operations by Segment

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 $14.5 billion USD of assets, approximately 866,000 customers and 2,601 employees as at December 31, 2025.

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

TEC’s approved regulated ROE range is 9.50 per cent to 11.50 per cent, based on an allowed equity capital structure of 54 per cent. An ROE of 10.50 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 and on EDGAR at www.sec.gov.


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Market and Sales


TEC Revenue and Sales Volumes by Customer Class
	Electric Revenues (%)		GWh Electric Sales Volumes (%)
For the year ended December 31	2025	2024	2025	2024
Residential	57.3	59.7	48.3	48.8
Commercial	26.4	27.1	30.7	30.8
Industrial	6.3	6.4	9.9	9.6
Other (1)	10.0	6.8	11.1	10.8
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.

Energy Sources and Generation

As at December 31, 2025, TEC owns 6,771 MW of generating capacity, of which 78 per cent is natural gas fired, 21 per cent is solar and 1 per cent is energy storage. TEC also owns approximately 2,200 kilometres of transmission facilities and 21,100 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 to Consolidated Net Income and Consolidated Adjusted Net Income

Florida Electric Utility’s contribution to consolidated net income was $607 million USD in 2025 (2024 – $468 million USD). Florida Electric Utility’s contribution to consolidated adjusted net income was $607 million in 2025 (2024 – $470 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 and on EDGAR at www.sec.gov.

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 2025, capital investments, including AFUDC, in the Florida Electric Utility segment were $1.6 billion USD (2024 – $1.4 billion USD). In 2026, capital investment is expected to be approximately $1.8 billion USD, including AFUDC. Capital projects include investment in generation reliability projects and storm hardening, grid modernization, and transmission expansion.


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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. TEC has substantially reduced CO2 emissions by significantly expanding the use of solar power, repowering Big Bend Unit 1 steam turbine, 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. On March 12, 2025, the EPA announced that this rule was under reconsideration. On June 11, 2025, the EPA announced a proposal to repeal all “greenhouse gas” emissions standards for the power sector under Section 111 of the Clean Air Act (CAA) and to repeal amendments to the 2024 MATS that directly result in coal-fired power plants having to shut down.

On August 1, 2025, the EPA released a proposal for the Reconsideration of 2009 Endangerment Finding and Greenhouse Gas Vehicle Standards. This finding has been the basis for the regulation of greenhouse gas emissions from motor vehicles and has been a critical component of the US federal government’s climate regulation efforts. If the Endangerment Finding is repealed, it could have significant implications for the power industry, as it would remove the legal authority for the EPA to regulate greenhouse gas emissions from power plants and other sources.

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. The final project required for compliance with the CCR Rule at Big Bend is the North Gypsum Stackout Area Drainage Improvements Project, which was completed 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.

The legacy rule finalized in May 2024 covers any landfill or impoundment in existence at an inactive power facility but not receiving CCRs as of 2015 (not applicable to Big Bend), or any CCR placed into the environment for beneficial use. TEC is currently evaluating the impact of the rule at the Big Bend Power Station and will be required to perform site evaluations in 2026 to determine the presence of any regulated CCR management units. The report for this first phase of the evaluations will be submitted by February 9, 2027. If determined to be present, additional groundwater monitoring for these units would begin to determine the need for additional corrective actions, possibly including CCR management unit remediation and closure. It is possible that the new EPA Administration may make revisions to the CCR Rules in general


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and the above rule deadlines. However, it is prudent for TEC to proceed with required compliance activities until such revisions occur.

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 completed a multi-year construction project to install new fish-friendly modified traveling screens and a fish return. 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 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. 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 wastewaters at each power station will be regulated under the Underground Injection Control program rather than the NPDES program. On March 12, 2025, the EPA announced that this rule was under reconsideration but this is not anticipated to have a material impact on TEC operations.

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”. On November 20, 2025, the EPA and the U.S. Army Corps of Engineers released a proposed rule revising the definition of “waters of the United States” applicable to all Clean Water Act programs. The final rule is expected to have environmental permitting implications for new TEC solar sites, transmission and distribution infrastructure, 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.


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Superfund and Former Manufactured Gas Plant Sites

Previously, TEC had been a potentially responsible party (“PRP”) for certain superfund sites through its Tampa Electric and former PGS divisions, as well as for certain former manufactured gas plant sites through its PGS division. As a result of the separation of the PGS division into a separate legal entity, PGS is also now a PRP for those sites (in addition to third party PRPs for certain sites). For further details, refer to Note 28, Commitments and Contingencies – Legal Proceedings – Superfund and Former Manufactured Gas Plant Sites, 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 and on EDGAR at www.sec.gov.

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.

NSPI

NSPI is the primary electricity supplier in Nova Scotia, providing electricity generation, transmission and distribution services to approximately 565,000 customers with $8.1 billion in assets and 2,486 employees, as at December 31, 2025.

NSPI is a public utility as defined in the Public Utilities Act and is subject to regulation under the Public Utilities Act by the NSEB. The Public Utilities Act gives the NSEB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are subject to NSEB 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 NSEB’s request.

NSPI has a FAM, approved by the NSEB, 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 and on EDGAR at www.sec.gov.

Market and Sales


NSPI Revenue and Electricity Sales Volumes by Customer Class
	Electric Revenues (%)		GWh Electric Sales Volumes (%)
For the year ended December 31	2025	2024	2025	2024
Residential	56.2	55.0	49.4	48.2
Commercial	27.4	27.5	28.8	28.8
Industrial	14.2	15.2	19.6	21.0
Other	2.2	2.3	2.2	2.0
Total	100.0	100.0	100.0	100.0


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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 2025, NSPI began operations of two 50 MW grid-scale battery facilities to enhance reliability. In addition, NSPI has contracts to purchase renewable energy from IPPs, and COMFIT participants, which own 573 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, until March 31, 2026, 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 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 network.

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 NSEB. NSPI complies with NPCC criteria and NERC standards for the design, planning and operation of NSPI’s portion of the interconnected bulk electric system.

For details on the IESO Nova Scotia and Nova Scotia Energy Reform Act, refer to the “General Development of the Business – Canadian Electric Utilities - NSPI” section below.

Transmission and Distribution

NSPI transmits and distributes electricity from its generating stations to its customers. NSPI’s transmission system consists of approximately 5,400 km of transmission facilities. The distribution system consists of approximately 28,700 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


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efficiency and reliability of energy in both provinces. NLH’s NS Block delivery obligations commenced on August 15, 2021, and 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 $182 million in 2025 (2024 – $232 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 2025 were $712 million (2024 – $487 million), including AFUDC. In 2026, NSPI expects to invest $720 million, including AFUDC, NSPI is primarily investing in capital projects to support power system reliability and reliable service for customers.

NSPML

In 2026, the capital investment at NSPML is expected to be approximately $40 million (2025 – $7 million).

Environmental Considerations

NSPI is subject to environmental laws and regulations set by both the Government of Canada and the Province of Nova Scotia (the “Province”). NSPI continues to work with both levels of government to comply with these laws and regulations, to maximize efficiency of emission control measures and minimize customer cost. NSPI anticipates that costs prudently incurred to achieve legislated reductions will be recoverable under NSPI’s regulatory framework.

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 2025 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.


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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	2025	2024	2025	2024
Residential	46.1	46.7	12.5	13.1
Commercial	31.7	32.5	27.8	26.3
Industrial	6.1	6.2	49.8	51.7
Other	16.1	14.6	9.9	8.9
Total	100.0	100.0	100.0	100.0

PGS

As at December 31, 2025, PGS serves approximately 523,000 customers with $3.3 billion USD in assets and 840 employees. The PGS system includes approximately 25,600 kilometres of natural gas mains and 14,800 kilometres of service lines. Natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) was 2 billion therms in 2025.

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. Base rates are determined in FPSC rate setting hearings which can occur at the initiative of PGS, the FPSC or other interested parties.

Beginning in 2026, the approved ROE range for PGS is 9.30 per cent to 11.30 per cent (2025 – 9.15 per cent to 11.15 per cent), based on an allowed equity capital structure of 54.7 per cent (2025 – 54.7 per cent). An ROE of 10.30 per cent (2025 – 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 and on EDGAR at www.sec.gov.

NMGC

As at December 31, 2025, NMGC serves approximately 553,000 customers with $1.6 billion USD in assets and 755 employees. NMGC’s system includes approximately 2,300 km of transmission lines and 18,200 km of distribution lines. Annual natural gas throughput was approximately 1 billion therms in 2025.

NMGC is subject to regulation by the NMPRC. Rates are set at a level that allows NMGC to collect total revenues or revenue requirements 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, 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 and on EDGAR at www.sec.gov.


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On August 5, 2024, Emera announced an agreement to sell NMGC. 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 and on EDGAR at www.sec.gov.

EBPC

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

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

Economic Dependence

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

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 $196 million USD in 2025 (2024 – $188 million USD). Gas Utilities and Infrastructure’s contribution to consolidated adjusted net income was $196 million USD in 2025 (2024 – $194 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 and on EDGAR at www.sec.gov.

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 investment in PGS in 2025 were $323 million USD, including AFUDC, (2024 – $323 million USD in the Gas Utilities and Infrastructure segment). In 2026, capital investment at PGS is expected to be approximately $445 million USD, including AFUDC. PGS will make investments to maintain the reliability of their systems and support customer growth.


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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 are hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov.

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

Other Electric Utilities

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

Market and Sales

Other Electric Utilities operating revenues for 2025 were $413 million USD (2024 – $413 million USD) and electric sales volumes for 2025 were 1,307 GWh (2024 – 1,307 GWh).

BLPC

As at December 31, 2025, BLPC serves approximately 137,000 customers with $547 million USD of assets and a workforce of 440 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 approximately 200 km of transmission lines, including major substations connected to the transmission and distribution system. The distribution system consists of approximately 4,000 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 November 2025, the Government of Barbados and BLPC agreed to new Transmission, Distribution, Sales and Dispatch (“T&D”) and Generation and Energy Storage (“G&S”) licenses. The G&S license will be valid until 2047, unless otherwise extended. The T&D License will be valid for 30 years. These new non-exclusive licenses have since been signed and will become effective upon the repeal of the existing license. BLPC continues to operate under its current statutory authority while preparing for the transition to the new licensing framework.

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.


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

GBPC

As at December 31, 2025, GBPC serves approximately 20,000 customers, with $378 million USD of assets and a workforce of 216 employees. GBPC owns 98 MW of oil-fired generation, approximately 100 kilometres of transmission facilities and 1,000 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 are hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov.

System Operation

BLPC and GBPC each have system control centres that co-ordinate and control their electric generation and transmission facilities with the goal of providing a reliable and secure electricity supply while maintaining economy of operations. Their 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 and consolidated adjusted net income was $31 million USD in 2025 (2024 – $35 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 and on EDGAR at www.sec.gov.

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 for 2025 were $67 million USD (2024 – $59 million USD), including AFUDC. In 2026, capital investment is expected to be approximately $110 million USD, including


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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 Emera’s subsidiaries and investments.

Business operations in the Other segment include Corporate; Emera Energy Services (EES), physical energy marketing and trading business; and a 50 per cent joint venture interest in Bear Swamp, a 660 MW pumped storage hydroelectric facility in northwestern Massachusetts.

Corporate includes 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.

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 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.

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.

Contribution to Consolidated Net Income and Adjusted Net Income

Other’s contribution to consolidated net income was a loss of $332 million in 2025 (2024 – loss of $686 million). Other’s contribution to consolidated adjusted net income was a loss of $301 million in 2025 (2025 – loss of $342 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 and on EDGAR at www.sec.gov.


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Capital Investment

In 2026, capital investment in the Other segment is expected to be approximately $10 million (2025 – $6 million).

GENERAL DEVELOPMENT OF THE BUSINESS

Three Year History and Changes Expected in 2026

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

On 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 allowed equity in the capital structure continues 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 2024 rate case decision, effective January 1, 2025. In February 2025, a motion for reconsideration on certain aspects of the final order was filed by an intervening party with the FPSC. On May 6, 2025, the FPSC denied the motion for reconsideration, except with respect to immaterial calculation corrections, and the final order was issued on June 11, 2025. In March 2025, two intervening parties each filed a notice of appeal to the Florida Supreme Court regarding the outcome of TEC’s 2024 base rate proceeding. On January 12, 2026, the intervening parties filed their briefs related to the appeal. To date, the FPSC has not responded to the briefs.

On September 4, 2025, TEC petitioned the FPSC to increase base revenue by $88 million USD to reflect the 2026 adjustment in accordance with its 2024 rate case decision. On November 4, 2025, the FPSC approved the adjustment, with new rates becoming effective January 1, 2026.

Fuel Recovery

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.


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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.

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 exceeded the storm reserve balance and therefore $377 million USD was deferred as a regulatory asset for future recovery. On February 4. 2025, the FPSC approved TEC’s petition for the recovery of $466 million USD of 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, which began in March 2025. The amount of cost-recovery is subject to a true-up mechanism with the FPSC.

For additional details on the storm reserve, 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 and on EDGAR at www.sec.gov.

Canadian Electric Utilities

NSPI

General Rate Application and Settlement Agreement

On February 2, 2023, the NSEB approved the General Rate Application (“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 increase of 6.5 per cent on January 1, 2024, with any under or over-recovery of fuel costs addressed through the NSEB’s established FAM process. On March 27, 2023 the NSEB issued a final order approving the electricity rates, effective on February 2, 2023 (“GRA decision date”).

Effective from the GRA decision date, the Settlement Agreement established a storm rider for each of 2023, 2024 and 2025, which gave NSPI the ability to apply to the NSEB for deferral and recovery of expenses if major storm restoration expense exceeds approximately $10 million in any given year. 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 NSEB approved the


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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 and concluding by December 31, 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 NSEB. The DSM rider was effective as of 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.

2025 GRA

On September 18, 2025, NSPI filed a consensus GRA with the NSEB, reflecting a settlement agreement reached with customer representatives. The GRA proposes average annual rate increases of 1.8 per cent in 2026 and 2.4 per cent in 2027. The proposed rates would result in annual revenue (fuel and non-fuel) increases of $62 million in 2026 and $108 million in 2027. The hearing for the matter concluded in January 2026 and a decision by the NSEB is expected by early Q2 2026.

Fuel Recovery

On April 17, 2024, the NSEB 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 NSEB related to the FLG. On November 29, 2024, the NSEB 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 NSEB approved NSPI’s application to increase 2025 fuel rates to service the incremental NSPML debt.

Hurricane Fiona

On June 27, 2024, the NSEB approved the deferred recognition of $25 million in incremental operating costs incurred during the Hurricane Fiona storm restoration efforts in September 2022. Following NSEB approval, the $25 million was reclassified to “Regulatory assets” from “Other long-term assets”. The NSEB 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 are hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov.


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Battery Energy Storage System (“BESS”) Project

On June 13, 2024, the NSEB approved $238 million of capital investment, including AFUDC, for the BESS Project. The project is comprised of three 50 MW, four-hour battery facilities. As of December 31, 2025, two facilities are in-service and the third facility is expected to be in service in 2026.

Wasoqonatl Transmission Line Project

On March 5, 2025, NSPI, the Canada Infrastructure Bank (“CIB”) and the Wskijinu’k Mtmo’taqnuow Agency (“WMA”) announced the Wasoqonatl transmission line project to create a reliability intertie between Nova Scotia and New Brunswick. The project is owned by a new regulated utility, WTI, which is wholly-owned by a newly formed limited partnership between NSPI, CIB and WMA. NSPI is responsible for providing construction, operation, maintenance and administrative services to WTI. NSPI has a 50 per cent indirect voting interest in WTI which is recorded as an “Investments subject to significant influence” on Emera’s Consolidated Balance Sheets, which are included in the Audited Financial Statements.

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 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 (“IESO Nova Scotia”).

On October 15, 2025, IESO Nova Scotia announced that the organization will be phased in over two phases during an 18-month period. On December 1, 2025, the first phase was completed following the transfer of system planning and interconnection functions. The second phase is expected to be complete in 2027 as IESO Nova Scotia assumes responsibility for system operations.

Clean Electricity Regulations

On December 17, 2024, Environment and Climate Change Canada released a finalized version of the Clean Electricity Regulations. The Clean Electricity Regulations 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 Clean Electricity Regulations is not anticipated to require significant capital investment incremental to NSPI’s planned capital investment driven by the Province’s goals to transition off coal and reach 80 per cent renewable electricity sales by 2030.

Nova Scotia Renewable Energy 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 2023 and 2024, and in 2025 met this target with more than 40 per cent of NSPI’s electric sales coming from renewable sources, subject to a compliance filing.

On April 6, 2023, the Province levied a $10 million penalty on NSPI for non-compliance with the RER compliance period ending in 2022. On May 26, 2023, NSPI initiated an appeal, through a proceeding with the NSEB, of the $10 million penalty levied on NSPI by the Province for non-compliance with the RER compliance period ending in 2022. The hearing in 2025 and NSPI is awaiting a decision.


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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 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 NSEB 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 NSEB 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.


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NSPML

Maritime Link Project

On October 4, 2023 and January 31, 2024, the NSEB 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 NSEB 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 NSEB 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 NSEB increased the monthly holdback amount from $2 million to $4 million beginning December 1, 2023.

On December 21, 2023, NSPML received NSEB 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 NSEB 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 NSEB 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.

On December 23, 2025, NSPML received an interim order from the NSEB to collect up to $199 million from NSPI for the recovery of costs associated with the Maritime Link in 2026, subject to a monthly holdback of up to $4 million. A final decision from the NSEB is pending. There was no holdback recorded for the year ended December 31, 2025.

On February 4, 2026, NSPML submitted an application with the NSEB requesting the termination of the holdback mechanism. A decision is anticipated in Q3 2026.

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 further details, see Note 4, Dispositions, 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 and on EDGAR at www.sec.gov.

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


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of debt and customary closing adjustments. As a result of the pending sale, NMGC’s assets and liabilities are classified as held for sale as of Q3 2024. The public hearing was held in November 2025. The transaction is expected to close in the first half of 2026, subject to certain approvals, including regulatory approval by the NMPRC. 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 and on EDGAR at www.sec.gov.

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 included $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 reflected 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 rates effective January 2024.

On March 31, 2025, PGS filed a rate case with the FPSC for new rates to become effective January 1, 2026. On August 13, 2025, PGS and the intervening parties filed a settlement agreement with the FPSC for a $67 million USD increase in 2026 annual base rates, which includes $7 million USD from the cast iron and bare steel replacement rider, and additional adjustments of $25 million USD in 2027 and up to $5 million USD in 2028 (subject to FPSC approval). This reflects a 10.30 per cent midpoint ROE and 54.7 per cent equity thickness. On October 31, 2025, the FPSC issued the final order approving the settlement.

NMGC

Base Rates

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 are hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov.

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


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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 was heard in December 2025, and will continue in early 2026. A decision is expected in 2026.

GBPC

Base Rates

On August 1, 2024, as required by the GBPA Operating Protocol and Regulatory Framework Agreement, GBPC filed a rate plan proposal. A review of the proposal by the GBPA is expected to commence in the first half of 2026.

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, 2024 and 2025 the fuel pass through charge was adjusted monthly, in-line with actual fuel costs.

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. In 2024, URCA filed a claim in the Supreme Court of the Bahamas, seeking an order that the GBPA be prohibited and restrained from considering and/or approving any adjustment to rates sought by GBPC. URCA contends that it has regulatory authority over electricity provision on Grand Bahama pursuant to the Electricity Act. Management does not expect that the outcome of the proceedings will have a material impact to Emera.

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 and on EDGAR at www.sec.gov.

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 earnings before interest, income taxes, depreciation, and amortization (“EBITDA”) for tax purposes. Any denied interest and financing expenses under the EIFEL regime can be carried forward indefinitely.


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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 were expected to be denied under the EIFEL legislation and, as a result, the financing structure was wound up. It was determined that Emera was more likely than not to realize the benefit of the current denied interest and financing expenses and therefore a $54 million deferred income tax asset and related income tax benefit was recorded during Q4 2024. In addition, Emera recognized a $4 million income tax benefit related to the reversal of a deferred income tax liability on the wind-up of the financing structure.

For further details, refer to Note 11, Income Taxes - Excessive Interest and Financing Expenses Limitation (“EIFEL”) Regime, 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 and on EDGAR at www.sec.gov.

New York Stock Exchange (“NYSE”) Listing

Emera filed a registration statement dated May 1, 2025 on Form 40-F with the SEC to register its common shares under Section 12 of the Securities Exchange Act of 1934. Emera subsequently completed the listing of its common shares on the NYSE and commenced trading on May 28, 2025. Emera’s common shares continue to be listed and traded on the Toronto Stock Exchange.

US One Big Beautiful Bill Act (“OBBBA”)

On July 4, 2025, the OBBBA was signed into law. The OBBBA makes permanent many of the expired and expiring tax provisions originally enacted in the Tax Cuts and Jobs Act of 2017. It also includes significant changes in future years to the timing and availability of several clean energy tax credits previously enacted in the Inflation Reduction Act, including the investment tax credit and production tax credit. On August 15, 2025, the Internal Revenue Service released guidance on determining when wind and solar projects have begun construction for purposes of qualifying for these tax credits. Emera’s 2025 financial statements were not materially impacted as a result of the enacted changes. Emera will continue to evaluate the future impact as additional information and guidance becomes available.

Financing Activity

ATM Program

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

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.

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.


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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, 187,600 common shares were issued under the ATM Program and an aggregate gross sales limit of $326 million remained available for issuance under the ATM Program until its expiry on November 4, 2025.

On December 5, 2025, Emera renewed its ATM Program by filing a prospectus supplement to the Company’s Canadian short form base shelf prospectus with the securities regulatory authorities in each of the provinces of Canada. At the same time, Emera filed a US prospectus supplement to the Company’s US base prospectus included in its US registration statement on Form F-10 with the SEC. The ATM Program 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 is expected to remain in effect until January 5, 2029.

During 2026, up to and including February 23, 2026, no common shares were issued under the ATM Program and an aggregate gross sales limit of $600 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 Series F First Preferred Shares would be converted into Series G First Preferred Shares on February 15, 2025.

On July 9, 2025, Emera announced that it would not redeem the currently outstanding Series A First Preferred Shares or the Series B First Preferred Shares on August 15, 2025. The holders of Series A Shares had the right, at their option, to convert all or any of their Series A Shares, on a one-for-one basis, into Series B First Preferred Shares and the holders of Series B First Preferred Shares had the right, at their option, to convert all or any of their Series B First Preferred Shares, on a one-for-one basis, into Series A First Preferred Shares, on August 15, 2025 (the “Conversion Date”).

On August 7, 2025, Emera announced, after having taken into account all shares tendered for conversion by holders of its Series A First Preferred Shares and Series B First Preferred Shares, as the case may be (collectively, the “Holders”), by the end of the conversion period, the Company has determined that there would be outstanding on the Conversion Date less than 1 million Series B Shares. Therefore, in accordance


Emera Incorporated – 2025 Annual Information Form		28

with certain rights, privileges, restrictions and conditions attaching to the Series A First Preferred Shares and the Series B First Preferred Shares, the Company advised the Holders that no Series A Shares would be converted into Series B First Preferred Shares and all remaining Series B First Preferred Shares would automatically be converted into Series A First Preferred Shares on a one-for-one basis on the Conversion Date. On the Conversion Date, there were 6 million Series A Shares and no Series B First Preferred Shares outstanding.

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, 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 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.

On September 25, 2025, EUSHI Finance, Emera US Holdings Inc. (“EUSHI”) and Emera filed a shelf registration statement on Form F-10 and Form F-3 (“Registration Statement”), with the Nova Scotia Securities Commission (“NSSC”) and the SEC under the US/Canada Multijurisdictional Disclosure System. The Registration Statement was filed in connection with the prospective offer and issue by EUSHI Finance of one or more series of senior and/or subordinated unsecured debt securities (“Debt Securities”), in an aggregate principal amount of up to $3 billion USD, during the 25-month period that the short form base shelf prospectus contained in the Registration Statement (“Base Shelf Prospectus”), including any further amendments thereto, remains valid. The Debt Securities may be offered in one or more transactions, at prices, with maturities and on terms to be set forth in one or more prospectus supplements to be filed with the NSSC and the SEC at the time of any such offering.

On October 3, 2025, EUSHI Finance completed an issuance of $750 million USD fixed-to-fixed reset rate junior subordinated notes, pursuant to the prospectus supplement dated September 29, 2025, to a base shelf prospectus. The notes initially bear interest at a rate of 6.25 per cent, and will reset on April 1, 2031, and every five years thereafter, to a rate per annum equal to the five-year US treasury rate plus 2.509 per cent, subject to an interest rate floor of 6.25 per cent. The notes mature on April 1, 2056. 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, plus accrued and unpaid interest on the notes to be redeemed, in accordance with the terms of the prospectus supplement; and otherwise, at the times and the redemption prices described in the prospectus supplement. The notes are fully and unconditionally guaranteed, on a joint, several and subordinated basis, by Emera, and EUSHI. Proceeds from this issuance were used for general corporate purposes, including repayment of existing debt.

WKSI Eligibility

The securities regulatory authorities in each of the provinces and territories of Canada published amendments to National Instrument 44-102 Shelf Distributions (“NI 44-102”) and other securities law instruments implementing a permanent expedited shelf prospectus regime (the “WKSI Rules”) for well


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known seasoned issuers, which came into force as of November 28, 2025. As at December 31, 2025 and as of the date hereof, the Company qualifies as a well-known seasoned issuer (“WKSI”) by virtue of its “qualifying public equity” (as defined under NI 44-102) and is therefore eligible to rely on the WKSI Rules.

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 and on EDGAR at www.sec.gov.

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 and on EDGAR at www.sec.gov.

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, 2025, 301,754,258 common shares, 6,000,000 Series A First Preferred Shares, 10,000,000 Series C First Preferred Shares, 5,000,000 Series E First Preferred Shares, 8,000,000 Series F First Preferred Shares, 12,000,000 Series H First Preferred Shares, 8,000,000 Series J First Preferred Shares, 9,000,000 Series L First Preferred Shares, 2,200,525 Barbados DRs and 1,814,135 Bahamas DRs were issued and outstanding.

Common Shares

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

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

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

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

Emera First Preferred Shares

The first preferred shares of each series rank on parity with the first preferred shares of every other series and are entitled to a preference over the second preferred shares, the common shares, and any other shares ranking junior to the first preferred shares with respect to the payment of dividends and the


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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, 2025, 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, 2025, 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 C First Preferred Shares, Series E First Preferred Shares, Series F First Preferred Shares, Series H First Preferred Shares, Series J First Preferred Shares and Series L First Preferred Shares are considered to be voting shares for purposes of the constraints on share ownership.

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


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CREDIT RATINGS

Emera has the following credit ratings by the Rating Agencies:


	Moody’s	S&P	Fitch
Corporate	Baa3	BBB-	BBB
Outlook	Negative	Stable	Stable
Senior unsecured debt program	Baa3	BBB-	BBB
Hybrid Notes	Ba1	BB+	BB+
Junior Subordinated Notes (1)	Ba1	BB+	BB+
First Preferred Shares	N/A	P-3 (high)	BB+

(1)

The Junior Subordinated Notes were issued by EUSHI Finance and are fully and unconditionally guaranteed by Emera and its subsidiary, Emera US Holdings Inc.

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 and on EDGAR at www.sec.gov.

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. Emera has increased dividends per common share paid for 19 consecutive years and has provided annual dividend growth guidance of 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 2025.

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		2025		2024		2023

Common Shares(1), (2), (3)	$	2.9075	$	2.8775	$	2.7875

Series A First Preferred Shares(4)	$	0.7186	$	0.5456	$	0.5456

Series B First Preferred Shares(5)	$	0.9451	$	1.6966	$	1.5583

Series C First Preferred Shares(6)	$	1.6085	$	1.6085	$	1.2873

Series E First Preferred Shares	$	1.1250	$	1.1250	$	1.1250

Series F First Preferred Shares(7)	$	1.3406	$	1.0505	$	1.0505

Series H First Preferred Shares(8)	$	1.5810	$	1.5810	$	1.3140

Series J First Preferred Shares(9)	$	1.0625	$	1.0625	$	1.0625

Series L First Preferred Shares(10)	$	1.1500	$	1.1500	$	1.1500

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

(2) On September 18, 2024, Emera approved an increase in the annual common share dividend rate from $2.87 to $2.90. The first payment was effective November 15, 2024.


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(3) On September 25, 2025, Emera approved an increase in the annual common share dividend rate from $2.90 to $2.93. The first payment was effective November 15, 2025.

(4) The Series A First Preferred Shares annual dividend rate was reset from $0.5456 to $1.2376 for the five year period commencing August 15, 2025 and ending on (and inclusive of) August 14, 2030.

(5) The Series B First Preferred Shares were all converted to Series A First Preferred Shares on August 15, 2025.

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

(7) The Series F First Preferred Shares annual dividend rate was reset from $1.0505 to $1.43724 for the five year period commencing February 15, 2025 and ending on (and inclusive of) February 14, 2030.

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

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

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

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

MARKET FOR SECURITIES

Trading Price and Volume

Emera’s common shares, Series A First Preferred Shares, Series 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 currently listed and posted for trading on the TSX under the symbols “EMA”, “EMA.PR.A”, “EMA.PR.C”, “EMA.PR.E”, “EMA.PR.F”, “EMA.PR.H”, “EMA.PR.J” and “EMA.PR.L”, respectively. Emera’s common shares are also listed on the NYSE under the symbol “EMA”. 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 common shares and preferred shares for each month of 2025 are set out In Appendix “C” of this AIF.

ATM Program

On December 5, 2025, Emera renewed its ATM Program by filing a prospectus supplement dated December 5, 2025 to the Company’s Canadian short form base shelf prospectus filed on December 5, 2025 with the securities regulatory authorities in each of the provinces of Canada; and a U.S. prospectus supplement dated December 5, 2025 to the Company’s U.S. base prospectus included in its U.S. registration statement on Form F-10, also filed on December 5, 2025 with the SEC. The ATM Program will allow the Company to issue up to $600 million of common shares from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price. The ATM Program is expected to remain in effect until January 5, 2029. For more information on the ATM Program, refer to “General Development of the Business – Financing Activity – ATM Program” section above.


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DIRECTORS AND OFFICERS

Directors

The following information is provided for each Director of Emera as at December 31, 2025:


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

Karen H. Sheriff (Chair), Picton, Ontario, Canada Chair of the Board since February 2025. Ms. Sheriff is past President and CEO of Q9 Networks Inc., and prior to that, President and CEO of Bell Aliant, Inc., from 2008 to 2014. She held senior leadership positions for more than nine years with BCE Inc. and currently serves on the BCE Inc. Board of Directors. She is a former member of the Board of Directors of CPP Investments and WestJet Airlines Ltd.	2021	(4)

Scott C. Balfour, Halifax, Nova Scotia, Canada A Director and President and Chief Executive Officer of Emera since March 2018. Mr. Balfour is a Director of many Emera subsidiaries, including being Chair of Tampa Electric Company and Nova Scotia Power Inc. He is a former director of Martinrea International Inc. He was Chief Operating Officer from 2016 to 2018 and was Executive Vice President and Chief Financial Officer of Emera from April 2012 to March 2016. From 1994 to 2011 he was Chief Financial Officer and then President of Aecon Group Inc., a Canadian publicly traded construction and infrastructure development company. He is also past Chair of the Ontario Energy Association.	2018	(5)

James V, Bertram, Calgary, Alberta, Canada Chair of the Board, Keyera Corporation. Formerly President, and Chief Executive Officer of Keyera from 1998 until 2015, when he became Executive Chair. Director of Methanex Corporation, the world’s largest producer and supplier of methanol to major international markets.	2018	Member of MRCC and NCGC

Isabelle Courville, Montréal, Québec, Canada Chair of the Board of Canadian Pacific Kansas City and previously served as President of Hydro-Québec Distribution and Hydro Québec TransÉnergie, as well as President of Bell Canada’s Enterprise Group and President and Chief Executive Officer of Bell Nordiq. Currently a member of the Board of Veolia Environment S.A., a French transnational company. Member of the Board of Directors of the Institute for Governance of Private and Public Organizations.	2025(1)	Member of AC and MRCC

Henry E. Demone, Lunenburg, Nova Scotia, Canada Former Chair of High Liner Foods, the leading North American processor and marketer of value-added frozen seafood. Mr. Demone was President of High Liner Foods since 1989 and its President and Chief Executive Officer from 1992 to May 2015. He was interim Chief Executive Officer of High Liner Foods from August 2017 until April 2018. Former Director of Saputo Inc. from June 2012 to September 2024.	2014	Chair of MRCC and Member of NCGC

Paula Y. Gold-Williams, San Antonio, Texas, U.S. Former President and CEO of CPS Energy, a fully integrated electric and natural gas municipal utility based in San Antonio, Texas. Currently serves as the Co-Chair of the Keystone Policy Center. Energy Pillar Co-Chair of Dentons’ Global Smart Cities & Communities Initiatives and Think 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 and MRCC

Kent M. Harvey, New York, New York, U.S. Former Chief Financial Officer for PG&E Corporation, an energy-based holding company, and the parent of Pacific Gas and Electric Company, one of the largest combined natural gas and electric energy companies in the United States.	2017	Chair of AC and Member of SRC


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Name, Residence, Principal Occupations During the Past Five Years	Director Since (2)	Committees (3)
B. Lynn Loewen, FCPA, FCA, Montreal, Quebec, Canada Member of the Board of Directors of National Bank of Canada, a Canadian Chartered Bank, Chair of its Audit Committee 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 the Chair of Kinaxis’ 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 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 broadband service provider, and a member of its Audit Committee from 2021 to 2023.	2013	Member of AC and NCGC
Brian J. Porter, Toronto, Ontario, Canada Former 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. Chair of the 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 Health Network Board of Trustees.	2024	Member of MRCC and SRC
Ian E. Robertson, Oakville, Ontario, Canada 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). Former member of the Board of Directors of Northern Genesis Acquisition Corp., Northern Genesis Acquisition Corp. II and Northern Genesis Acquisition Corp. III. Former Director of Embark Technology, Inc., an autonomous vehicle company, Largo Resources Ltd., Algonquin Power and Atlantica Sustainable Infrastructure plc.	2022	Chair of SRC and Member of AC
M. Jacqueline Sheppard, Calgary, Alberta, Canada Formerly Chair of the Board from May 2014 until February 2025.(6) Director of Suncor Energy Inc., a Canadian integrated energy company and of ARC Resources Ltd., a publicly traded Canadian energy company. Former Director of Alberta Investment Management Corporation (AIMCo), an institutional investment manager. Former Executive Vice President, Corporate and Legal of Talisman Energy Inc. Founder and former Lead Director of Black Swan Energy Inc., an Alberta upstream energy company, which was sold in July 2021. Former Director of Cairn Energy PLC, a publicly traded UK-based international upstream company, as well as former director of the general partner of Pacific Northwest LNG LP and Chair of the Research and Development Corporation of the Province of Newfoundland and Labrador, a provincial Crown corporation, until June 2014.	2009	—
Jochen E. Tilk, Toronto, Ontario, Canada Former Executive Chair of Nutrien Ltd., a Canadian global supplier of agricultural products and services based in Saskatoon, Saskatchewan. Former President and Chief Executive Officer of Potash Corporation of Saskatchewan. Mr. Tilk is Chair of the Board of AngloGold Ashanti Limited, a publicly listed international gold mining company, based in London, U.K. He is also Chair of the Princess Margaret Cancer Foundation, a not-for-profit organization.	2018	Chair of NCGC, Member of MRCC and SRC
Carla M. Tully, Arlington, Virginia, U.S. Former Chief Executive Officer and Co-Founder of Earthrise Energy, PBC, an 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 advisor to several energy transition startups.	2024	Member of AC and SRC


Emera Incorporated – 2025 Annual Information Form		36

(1) It was announced by the Company on September 17, 2025, that Isabelle Courville had been appointed to Emera’s Board of Directors.

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

(3) Board Committees as of December 31, 2025: Audit Committee (AC), Safety and Risk Committee (SRC), Management Resources and Compensation Committee (MRCC), and Nominating and Corporate Governance Committee (NCGC).

(4) Ms. Sheriff was appointed as Chair of the Board of Emera effective February 21, 2025. As Chair of the Board, she is no longer a member of any committee but attends all committee meetings.

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

(6) Ms. Sheppard retired from Emera’s Board of Directors, effective January 20, 2026.

Officers

The Officers of Emera as at December 31, 2025 were as follows:




Name and Residence		Principal Occupations During the Past Five Years
Scott C. Balfour President and Chief Executive Officer Halifax, Nova Scotia, Canada		A Director and President and Chief Executive Officer of Emera since March 2018.(1)
Jared B. Green Chief Financial Officer (2) Halifax, Nova Scotia, Canada		Chief Financial Officer of Emera since December 2025. Before joining Emera, Jared served as President and CEO of TriSummit Utilities, formerly AltaGas Canada, a regulated natural gas utility and renewable power business. He previously held senior roles at AltaGas Ltd., including President, Canadian Utilities; President, ENSTAR Natural Gas Company; and Vice President and Corporate Controller.
Archibald Collins (3) President and Chief Executive Officer, Tampa Electric Company 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 CEO of Grand Bahama Power, Executive Vice President Commercial Operations with Emera Energy, and Chief Operating Officer of Tampa Electric.
Peter Gregg (4) President and Chief Executive Officer, NSPI (5) Halifax, Nova Scotia, Canada		President and Chief Executive Officer of NSPI since October 2020, and Chair of ENL. Prior to that the President and Chief Executive Officer of the Independent Electricity System Operator in Ontario. Previously, the President and Chief Executive Officer of Enersource from 2014 to 2016 and before that Chief Operating Officer at Hydro One Networks.
Karen E. Hutt Chief Strategy and Growth Officer Halifax, Nova Scotia, Canada		Chief Strategy and Growth Officer since 2025. Prior to that, Executive Vice-President, Business Development and Strategy of Emera since October 2019. Previously, President and Chief Executive Officer of NSPI since August 2016.
Helen Wesley (6) President & Chief Executive Officer, Peoples Gas System Tampa, Florida, U.S.		President and CEO of Peoples Gas since 2020. Prior to this, she was with ENMAX Corporation, where she served as CFO and executive vice president of finance and information technology.
R. Michael Roberts Chief Human Resources Officer Halifax, Nova Scotia, Canada		Chief Human Resources Officer of Emera and NSPI since December 2014. Director of EBPC since March 2024.
Michael R. Barrett Executive Vice-President and General Counsel 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 Emera, Senior Partner and head of the power and climate change practice groups at Bennett Jones LLP in Toronto.


Emera Incorporated – 2025 Annual Information Form		37




Name and Residence		Principal Occupations During the Past Five Years
Brian C. Curry Corporate Secretary 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 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 table.

(2)

Effective December 1, 2025, Jared B. Green became Emera’s new Chief Financial Officer, succeeding Greg W. Blunden.

(3)

Mr. Collins is included in Emera’s list of Officers in his capacity as the President and CEO of TEC, which comprises the Florida Electric Utility segment, a principal business unit of Emera. Mr. Collins also has oversight and responsibility for Corporate Safety for Emera.

(4)

Mr. Gregg is included in Emera’s list of Officers in his capacity as the President and CEO of NSPI and Chair of ENL, which together comprises a substantial portion of the Canadian Electric Utilities segment, a principal business unit of Emera. Mr. Gregg also has oversight and responsibility for Corporate Sustainability and Environment for Emera.

(5)

It was announced on February 10, 2026 that Mr. Vivek Sood will succeed Mr. Gregg as President and CEO of NSPI effective March 1, 2026. Mr. Gregg will become Executive Vice President, Strategy and Policy for Emera.

(6)

Ms. Wesley is included in Emera’s list of Officers in her capacity as the President and CEO of PGS, which comprises a substantial portion of the Gas Utilities and Infrastructure segment, a principal business unit of Emera. Ms. Wesley also has oversight and responsibility for Enterprise Risk and Insurance for Emera.

As at December 31, 2025, the Directors and Officers, in total, beneficially owned or controlled, directly or indirectly, 269,301 common shares or less than 1 per cent of the issued and outstanding common shares of Emera, before giving effect to the exercise of options to purchase common shares held by such Directors and Officers. The Company collects this information from the Directors and Officers but otherwise Emera has no direct knowledge of individual holdings of Emera’s securities.

AUDIT COMMITTEE

The Audit Committee of Emera is composed of the following six members, all of whom are independent Directors: Kent M. Harvey (Chair), Isabelle Courville, Paula Gold-Williams, B. Lynn Loewen, 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.

Isabelle Courville

Ms. Courville is the former President of Hydro Quebec Distribution and Hydro-Quebec TransEnergie and has held various executive roles at Bell Canada, including President of Bell Canada’s Enterprise Group and


Emera Incorporated – 2025 Annual Information Form		38

President and Chief Executive Officer of Bell Nordiq. Ms. Courville is Chair of the Board of Canadian Pacific Kansas City (CPKC) and has chaired its Audit and Finance Committee as well as its Management Resources and Compensation Committee. Chair of the Board of Laurentian Bank from 2013 until 2019 and served on the Board of Directors of SNC-Lavalin Group Inc., Gecina S.A., a France-based real estate investment trust, and Miranda Technologies, a world-leading provider of hardware and software solutions for the television broadcast, cable, satellite and IPTV industry. In addition to CPKC, Ms. Courville is currently a member of the Board of Veolia Environment S.A., a French transnational company with activities in three main service and utility areas traditionally managed by public authorities—water management, waste management and energy services. She is also a member of the Board of Directors of the Institute for Governance of Private and Public Organizations. Ms. Courville holds a degree in Engineering Physics from the École Polytechnique de Montréal and a Bachelor’s Degree in Civil Law from McGill University. In 2021, she became Fellow of the Institute of Corporate Directors, Canada’s preeminent distinction for Directors.

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 also 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 in Texas. 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 as Kinaxis’ Audit Committee Chair. Chancellor of Mount Allison University, Chair of its Nominating and Governance Committee and a member of its Executive Committee from 2018 to 2025 and a member of its Board of Regents from 1998 to 2008, serving as Chair from 2007 to 2008. Ms. Loewen was a member of the Board of Directors of Gildan Activewear Inc., a Canadian apparel manufacturer in 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 of Nova Scotia and has received the Directors Designation from the Institute of Corporate Directors.


Emera Incorporated – 2025 Annual Information Form		39

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 Lion Electric Company. 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.

Carla M. Tully

She is the former Chief Executive Officer and Co-Founder of Earthrise Energy, PBC, an energy transition company she developed and grew into a successful independent power producer. 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. 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. Ms. Tully serves on the boards of Pattern Energy and the Citizens for Responsible Energy Solutions Forum. She is a Senior Advisor for the Canadian Pension Plan Investment Board (CPPIB) and an advisor to several energy transition startups. She also served on the Board of Nikola Corporation. She holds a Master of Business Administration from Columbia Business School, 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. She received the 2016 UK Institute of Directors’ Award – Director of the Year for Corporate Responsibility.

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.


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Auditors’ Fees

The aggregate fees billed by Ernst & Young LLP, the Company’s external auditors, during the fiscal years ended December 31, 2025 and 2024 respectively, were as follows:


Service Fee	2025 ($)	2024 ($)
Audit Fees (1)	7,237,801	5,689,398
Audit-Related Fees (2)	1,001,206	240,080
Tax Fees (3)	292,101	323,252
All Other Fees	-	-
Total	8,531,108	6,252,730

(1)

The Auditors’ fees for the 2023 through 2025 period were based on a three-year audit fee proposal subject to auditor appointment and audit fee approval each year. The Auditors’ fees are reflective of market rates for professional services.

(2)

Audit-related fees for Emera relate to fees associated with agreed upon procedures over rate-case filings and the audit of pension plans. Audit-related fees for 2025 also include fees incurred for additional work performed in preparation of Emera’s first integrated audit required under the Sarbanes-Oxley Act in 2026.

(3)

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

CERTAIN PROCEEDINGS

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

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

(a)

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

(b)

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

(2)

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

(3)

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

(4)

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

Carla M. Tully was a director of Nikola Corporation (“Nikola”) until December 12, 2025. In February, 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. In September, 2025, the U.S. Bankruptcy Court entered an order confirming Nikola’s Plan of Liquidation, which contemplated the establishment of a Liquidating Trust to complete the wind-down of Nikola’s operations.


Emera Incorporated – 2025 Annual Information Form		41

CONFLICTS OF INTEREST

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

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

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

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

NO INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

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

MATERIAL CONTRACTS

Emera did not enter into any material contracts outside the ordinary course of business during the year ended December 31, 2025, nor has it entered into any material contracts outside the ordinary course of business prior to the year ended December 31, 2025 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. Equiniti Trust Company, LLC, with its principal office at 28 Liberty Street, Floor 53, New York, New York 10005, USA, acts as Emera’s US transfer agent and registrar for its common shares.

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).


Emera Incorporated – 2025 Annual Information Form		42

ADDITIONAL INFORMATION

Additional information relating to Emera may be found under Emera’s profile on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov, or upon request to the Corporate Secretary, Emera Incorporated, P.O. Box 910, Halifax, N.S., B3J 2W5, or telephone (902) 233-4084. 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, on EDGAR at www.sec.gov and on its corporate website at www.emera.com.


Emera Incorporated – 202 5 Annual Information Form		43

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 and on EDGAR at www.sec.gov;

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

“AIF” or “Annual Information Form” means this 2025 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, 2025 and December 31, 2024, together with the auditors’ report thereon, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov;

“Bahamas DRs” means the DRs listed on BISX;

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

“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;

“BSE” means the Barbados Stock Exchange;

“CAD” means Canadian dollars;

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

“CIB”, means the Canada Infrastructure Bank;

“COMFIT” means the Nova Scotia Community Feed in Tariff program which was 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;

“Cybersecurity Incident” means a cybersecurity incident discovered by Emera and NSPI on April 25, 2025 involving unauthorized access into certain parts of its Canadian IT network and servers supporting portions of its business applications;

“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;

“DSM” means demand-side management;

“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;


Emera Incorporated – 2025 Annual Information Form		44

“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;

“EDGAR” means the SEC’s system for Electronic Data Gathering, Analysis and Retrieval available at www.sec.gov;

“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 NSEB.

“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, whose common shares are listed and traded on the TSX and the NYSE 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” means EUSHI Finance, Inc., 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 NSEB;

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

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

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

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

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

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

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

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

“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;


Emera Incorporated – 2025 Annual Information Form		45

“IESO Nova Scotia” means the Nova Scotia Independent Energy System Operator;

“IMP” means integrity management programs;

“IPPs” means independent power producers;

“Junior Subordinated Notes” means the Subordinated Notes (2024) and the Subordinated Notes (2025);

“km” means kilometre(s);

“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;

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

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

“MD&A” means Emera’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2025, a copy of which is available electronically under Emera’s profile on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov;

“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” (formerly the UARB) means Nova Scotia Energy Board, the independent regulator of NSPI and NSPML;

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

“NYSE” means the New York Stock Exchange;

“Officers” mean the executive officers of Emera, as defined in Part 1 of National Instrument 51-102, 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;


Emera Incorporated – 2025 Annual Information Form		46

“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 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;

“SEC” means the United States Securities and Exchange Commission;

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

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

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

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

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

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

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

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

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

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

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

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

“Subordinated Notes (2024)” means the $500 million USD aggregate principal amount of 7.625% fixed-to-fixed reset rate junior subordinated notes due 2054, issued by EUSHI Finance and fully and unconditionally guaranteed by Emera and its subsidiary, Emera US Holdings Inc.;


Emera Incorporated – 2025 Annual Information Form		47

“Subordinated Notes (2025)” means the $750 million USD aggregate principal amount of 6.25% fixed-to-fixed reset rate junior subordinated Notes due 2056, issued by EUSHI Finance and fully and unconditionally guaranteed by Emera and its subsidiary, Emera US Holdings Inc.;

“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;

“therm” means a unit of heat energy equivalent to 100,000 British thermal units (BTUs);

“TSX” means The Toronto Stock Exchange;

“UARB” means the Nova Scotia Utility and Review Board, which was replaced by the NSEB, the independent regulator of NSPI;

“USD” means U.S. dollars; and

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


Emera Incorporated – 2025 Annual Information Form		48

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

As of December 31, 2025, the following series of First Preferred Shares have been authorized:

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

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

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

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

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

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

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

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

Subject to automatic conversion conditions including the right of Emera to redeem the Series B, D, G, I and K First Preferred Shares, the holders of Series B, D, G, I and K First Preferred Shares have the right to convert any or all of their Series B, D, G, I and K First Preferred Shares into an equal number of Series A,


Emera Incorporated – 2025 Annual Information Form		49

C, F, H and J First Preferred Shares respectively. In addition, Series B, D, G, I and K First Preferred Shares may be automatically converted by Emera into Series A, C, F, H and J First Preferred Shares, respectively if Emera determines that, following conversion by the holders, there would be less than 1,000,000 Series B, D, G, I and K First Preferred Shares outstanding.

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 First Preferred Shares	Initial Redemption / Interest Reset Date	Subsequent Redemption / Conversion / Interest Reset Dates	Spreads

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

Series B	August 15, 2020	August 15, 2025 (1) 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	–	–

(1)

The Company announced on August 7, 2025 that, having taken into account all shares tendered for conversion by holders of its Series A Shares and Series B Shares, no Series A Shares would be converted into Series B Shares and all remaining Series B Shares would automatically be converted into Series A Shares on a one-for-one basis, on August 15, 2025.


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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, 2025, there were no Series 2016-A Conversion, First Preferred Shares issued and outstanding.

Holders of Series 2016-A Conversion, First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except: (i) where entitled by law; (ii) for meetings of the holders of first preferred shares as a class and holders of Series 2016-A Conversion, First Preferred Shares as a series; and (iii) in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the Series 2016-A Conversion, First Preferred Shares.

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.


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APPENDIX “C” - Monthly Trading Volume and High and Low Price for

Emera’s Common and Preferred shares in 2025

MARKET FOR SECURITIES

Common Shares

Emera’s common shares are traded on the TSX in Canada and on the NYSE in the U.S. The following table sets forth the reported high and low trading prices and trading volumes, on a monthly basis for the year ended December 31, 2025, for the common shares on the TSX and NYSE in Canadian Dollars and U.S. Dollars, respectively.


	2025 Trading Prices and Volumes – Common Shares
	TSX			NYSE
Month	High ($)	Low ($)	Volume	High ($)	Low ($)	Volume
January	55.70	51.23	33,099,278	–	–	–
February	58.73	54.36	32,367,046	–	–	–
March	61.33	57.73	21,450,064	–	–	–
April	63.13	56.59	33,710,829	–	–	–
May	63.31	59.02	31,050,919	46.00	44.55	179,896
June	63.19	60.17	19,460,734	46.14	43.90	3,332,993
July	65.35	61.33	16,635,477	47.20	44.86	1,718,652
August	67.42	64.08	20,353,250	49.01	46.51	3,181,463
September	66.80	63.17	17,496,272	48.01	45.77	3,134,395
October	69.62	66.18	25,160,873	49.77	47.36	3,054,950
November	69.09	66.19	26,874,327	49.38	46.94	3,590,135
December	68.48	64.79	17,329,037	49.51	46.87	4,736,914

Preferred Shares

Emera’s Series A 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 on the TSX. The Series B First Preferred Shares were previously listed on the TSX prior to being converted to Series A first Preferred Shares on August 15, 2025.

The following tables set forth the reported high and low trading prices and volumes for 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 on a monthly basis for the year ended December 31, 2025.


	2025 Trading Prices and Volumes – First Preferred Shares
	Series A First Preferred Shares			Series B First Preferred Shares
Month	High ($)	Low ($)	Volume	High ($)	Low ($)	Volume
January	17.93	16.51	51,309	18.50	16.92	25,175
February	17.38	17.00	108,095	17.72	17.03	25,745
March	17.40	16.67	123,552	18.00	16.55	16,908
April	16.81	15.79	66,444	16.98	15.36	36,439
May	17.15	16.43	77,769	17.12	16.49	114,499
June	18.78	17.06	126,733	18.80	17.10	120,818
July	20.69	18.79	584,305	20.65	18.90	58,986
August	21.34	20.00	548,974	21.20	20.00	17,745
September	20.80	20.22	174,274	–	–	–
October	21.36	20.54	492,104	–	–	–
November	21.43	20.74	42,712	–	–	–
December	22.43	21.00	137,051	–	–	–


Emera Incorporated – 2025 Annual Information Form		52


	Series C First Preferred Shares			Series E First Preferred Shares
Month	High ($)	Low ($)	Volume	High ($)	Low ($)	Volume
January	24.07	23.50	172,231	19.36	18.58	63,057
February	23.88	23.41	76,031	19.46	18.65	58,557
March	23.68	22.62	201,659	19.85	19.15	123,450
April	23.80	21.47	291,045	19.64	18.12	46,539
May	24.23	22.75	109,708	19.45	18.64	29,625
June	24.65	24.00	59,350	19.49	18.90	36,607
July	24.84	24.30	125,517	20.22	19.25	64,057
August	24.67	24.08	101,173	20.31	19.48	193,531
September	25.18	24.60	156,476	20.78	20.15	176,421
October	25.49	24.86	222,708	21.20	20.30	43,256
November	25.49	24.60	120,358	21.09	19.39	102,045
December	25.49	25.00	80,992	20.82	19.97	51,776


	Series F First Preferred Shares			Series H First Preferred Shares
Month	High ($)	Low ($)	Volume	High ($)	Low ($)	Volume
January	22.80	21.25	136,635	25.00	23.99	173,497
February	22.60	21.87	380,040	24.73	23.98	369.491
March	22.45	21.70	181,148	24.51	23.71	76,417
April	22.00	20.30	144,011	24.70	21.58	119,264
May	22.41	21.20	443,862	24.97	23.65	216,571
June	23.54	22.42	94,457	25.06	24.72	63,101
July	24.39	23.50	70,932	25.40	24.99	98,841
August	24.45	23.99	163,419	25.25	24.71	92,174
September	24.39	24.00	298,048	25.50	24.97	103,529
October	24.89	24.25	65,589	25.47	25.01	96,715
November	24.99	24.16	77,840	25.47	24.61	94,624
December	25.44	24.46	365,860	26.02	24.99	71,710


	Series J First Preferred Shares			Series L First Preferred Shares
Month	High ($)	Low ($)	Volume	High ($)	Low ($)	Volume
January	24.10	22.80	46,224	19.55	18.99	133,744
February	24.18	23.39	188,647	19.76	19.05	72,045
March	23.95	23.25	21,725	20.21	19.59	71,469
April	23.75	21.43	107,149	19.93	18.50	57,885
May	24.30	22.64	41,194	19.56	19.11	22,862
June	24.60	23.86	53,983	19.65	18.99	124,829
July	25.14	24.27	75,704	20.44	19.50	86,265
August	25.01	24.72	162,646	20.70	19.91	162,621
September	25.10	24.74	93,421	20.95	20.40	205,918
October	25.33	25.00	144,766	21.41	20.39	60,630
November	25.51	25.05	580,435	21.24	19.26	157,465
December	25.44	25.02	133,082	20.66	20.22	82,893

Depository Receipts

The Barbados DRs are traded on the BSE and the Bahamas DRs are traded on the BISX. The monthly trading volumes, if any, for each of the Barbados DRs and the Bahamas DRs are not material.


Emera Incorporated – 2025 Annual Information Form		53

APPENDIX “D”

LOGO

EMERA INCORPORATED

AUDIT COMMITTEE

CHARTER

May 2025

EMERA INCORPORATED

AUDIT COMMITTEE

CHARTER

PART I

MANDATE AND RESPONSIBILITIES

Committee Purpose

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

the quality and integrity of Emera’s financial statements;

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

the internal audit and assurance process;

the qualifications, independence and performance of the external auditors;

major financial risk exposures;

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

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

1.	Financial Reporting

(a)

The Committee shall review and assess the completeness and clarity of, and recommend Board approval of:

(i)

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

(ii)

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

(iii)

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

In doing so, the Committee shall discuss the above with management and Emera’s external auditors.

(b)

The Committee shall discuss with management any earnings press releases or other press releases containing financial information, as well as any financial information and earnings guidance provided by management to analysts and ratings agencies. Such discussions may be in general terms and may occur after the issuance of such press releases or the disclosure of such financial information or earnings guidance in situations where it is impractical for management to discuss with the Committee beforehand.


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EMERA INCORPORATED

AUDIT COMMITTEE

CHARTER

(c)

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

(d)

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

2.	External Auditors

(a)

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

(b)

Once appointed, the external auditor shall report directly to the Committee, and the Committee shall oversee the work of the external auditor concerning the preparation or issuance of the auditor’s report or the performance of other audit, review or attest services for Emera.

(c)

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

(d)

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

(e)

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

(f)

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

(g)

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

(h)

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


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EMERA INCORPORATED

AUDIT COMMITTEE

CHARTER

3.	Non-Audit Services

(a)

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

(b)

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

(c)

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

4.	Oversight and Monitoring of Audits

(a)

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

(b)

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

(c)

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

(d)

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

(e)

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

5.	Oversight and Review of Accounting Principles and Practices

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

(a)

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

(b)

all significant financial reporting issues and judgments made in connection with the preparation of the financial statements, including the effects of alternative methods within U.S. generally accepted accounting principles (“U.S. GAAP”) on the financial statements


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EMERA INCORPORATED

AUDIT COMMITTEE

CHARTER

and any “other opinions” sought by Management from an independent auditor, other than the Company’s external auditors, with respect to the accounting treatment of a particular item, and other material written communications between the external auditors and management;

(c)

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

(d)

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

(e)

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

(f)

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

(g)

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

(h)

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

(i)

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

6.	Hiring Policies

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

7.	Pension Plans

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

8.	Oversight of Finance Matters

(a)

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


Emera Incorporated – 2025 Annual Information Form		57

EMERA INCORPORATED

AUDIT COMMITTEE

CHARTER

(b)

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

(c)

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

(d)

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

(e)

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

(f)

The Committee shall review and oversee all related party transactions required to be disclosed pursuant to Canadian securities laws for potential conflicts of interest and will prohibit such a transaction if it determines that it creates a conflict that is potentially detrimental to the interests of Emera and its shareholders. In addition, the Committee may also initiate a review of any and all related party transactions required to be disclosed pursuant to any accounting standards that are permitted under applicable securities laws for the purposes of determining whether appropriate disclosures have been made.

9.	Internal Controls

The Committee shall oversee:

(a)

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

(b)

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

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

The Committee will carry out the following specific duties:

(c)

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


Emera Incorporated – 2025 Annual Information Form		58

EMERA INCORPORATED

AUDIT COMMITTEE

CHARTER

(d)

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

(e)

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

10.	Internal Auditor

(a)

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

(b)

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

(c)

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

(d)

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

(e)

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

(f)

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

(g)

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


Emera Incorporated – 2025 Annual Information Form		59

EMERA INCORPORATED

AUDIT COMMITTEE

CHARTER

(h)

The Committee shall, at least annually, review the independence of the internal audit function and shall make recommendations to the Board on appropriate actions to be taken which the Committee deems necessary to protect and enhance the independence of the internal audit function.

(i)

The Committee shall review the results of an external assessment, performed every five years by a qualified independent assessor or assessment team, of the internal audit function in conformance with 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 non-compliance with legal and regulatory requirements;

(b)

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

(c)

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

(d)

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

(e)

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

13.	Limitation on Authority

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


Emera Incorporated – 2025 Annual Information Form		60

EMERA INCORPORATED

AUDIT COMMITTEE

CHARTER

PART II

COMPOSITION

14.	Composition

(a)

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

(b)

The Board shall appoint members to the Committee who are financially literate, as required by applicable legislation and stock exchange rules, which at a minimum requires that Committee members have the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by Emera’s financial statements. In addition, at least one member of the Committee shall be an Audit Committee Financial Expert (as defined below).

(c)

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

(d)

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

(e)

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

PART III

COMMITTEE PROCEDURE

15.

Meetings

(a)

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

(b)

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

(c)

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


Emera Incorporated – 2025 Annual Information Form		61

EMERA INCORPORATED

AUDIT COMMITTEE

CHARTER

(d)

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

16.	Separate Sessions

(a)

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

(b)

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

(c)

The Committee shall meet periodically without Management present.

17.

Quorum

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

18.

Chair

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

19.	Secretary and Minutes

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

20.	Board Relationships and Reporting

The Committee shall:

(a)

Review annually the Committee’s Charter and complete an annual performance evaluation of the Committee;

(b)

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


Emera Incorporated – 2025 Annual Information Form		62

EMERA INCORPORATED

AUDIT COMMITTEE

CHARTER

(c)

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

(d)

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

21.

Powers

The Committee shall:

(a)

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

(b)

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

(c)

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

22.	Experts and Advisors

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

23.

Funding

Emera will ensure the Committee has appropriate funding, as determined by the Committee, for payment of (1) compensation to any registered public accounting firm (including its external auditors) engaged to prepare or issue an audit report or perform other audit, review or attest services; (2) compensation to any independent counsel or other advisers, as the Committee determines necessary to carry out its duties; (3) and ordinary administrative expenses of the Committee.

24.	Definitions

“Audit Committee Financial Expert” means a person who has the following attributes:

(a)

an understanding of U.S. GAAP and financial statements;

(b)

the ability to assess the general application of such principles in connection with the accounting for estimates, accruals and reserves;

(c)

experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to


Emera Incorporated – 2025 Annual Information Form		63

EMERA INCORPORATED

AUDIT COMMITTEE

CHARTER

the breadth and complexity of issues that can reasonably be expected to be raised by Emera’s financial statements, or experience actively supervising one or more persons engaged in such activities;

(d)

an understanding of internal controls and procedures for financial reporting; and

(e)

an understanding of audit committee functions, acquired through any one or more of the following:

(i)

education and experience as a principal financial officer, principal accounting officer, controller, public accountant or auditor or experience in one or more positions that involve the performance of similar functions;

(ii)

experience actively supervising a principal financial officer, principal accounting officer, controller, public accountant, auditor or person performing similar functions;

(iii)

experience overseeing or assessing the performance of companies or public accountants with respect to the preparation, auditing or evaluation of financial statements; or

(iv)

other relevant experience.


Emera Incorporated – 2025 Annual Information Form		64

EX-99.2 4 d845370dex992.htm EX-99.2 EX-99.2

Exhibit 99.2

Management’s Discussion &

Analysis

As at February 23, 2026

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, 2025 relative to the same periods in 2024

and selected financial information for 2023; and its financial

position as at December 31, 2025 relative to

December 31, 2024. 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, 2025. 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 and on EDGAR

at www.sec.gov.

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, 2025, 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 Energy Board (“NSEB”), formerly Nova Scotia

Utility and Review Board

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”)

NSEB

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

Wasoqonatl Transmission Incorporated ("WTI")

NSEB

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” and

“forward-looking statements” (collectively,

“FLI”)

within the meaning of applicable Canadian and US securities

laws, including the United States Private

Securities Litigation Reform Act of 1995, which reflect the

current view with respect to the Company’s

expectations regarding future growth, results of operations,

performance, earnings, capital investment,

sales volumes, recovery of costs, timing of regulatory decisions,

the expected timing and outcome of the

pending sale of NMGC, the expected impact of Cybersecurity

Incident (as defined herein) on the

Company’s financial position and results of operations,

information technology (“IT”) systems restoration,

insurance recoveries, and business continuity processes as

well as other matters relating to the

Cybersecurity Incident, business prospects and opportunities,

and may not be appropriate for other

purposes. 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

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; system 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; potential impacts of trade

disputes and tariffs; estimated energy

consumption rates; maintenance of adequate insurance

coverage and receipt of proceeds; changes in

customer energy usage patterns; developments in technology

that could impact demand for electricity;

climate risk; weather risk, including higher frequency and

severity of weather events; risk of wildfires;

unanticipated maintenance and other expenditures; derivative

financial instruments and hedging; interest

rate risk; inflation risk; counterparty risk; disruption of fuel

supply; 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; risks and

costs associated with failure of IT infrastructure and

cybersecurity incidents including IT systems restoration and

business continuity processes; uncertainties

associated with infectious diseases, pandemics and similar

public health threats; risks associated with

health and safety; 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/NYSE: 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, Canada.

Emera’s business strategy is centred on continued

investment in its regulated utilities, combined with a

focus on operational excellence and efficiency,

to safely and reliably deliver energy to its 2.7 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 2025, Emera’s regulated cost

-of-service utilities in Florida accounted for 67

per cent of average consolidated rate base, with Atlantic

Canada comprising 25 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 2026 through 2030 and

is focused on delivering value for customers through prudent

investments in reliability and system

resiliency, infrastructure

modernization, expansion to address customer growth, integration

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

2026

2027

2028

2029

2030

Total

Capital investment plan

4,020

3,730

4,140

4,180

4,330

20,400

Average consolidated rate base:

US operations

23,180

25,100

27,140

29,300

31,480

Canadian operations

7,340

7,660

7,990

8,320

8,580

Total

30,520

32,760

35,130

37,620

40,060

*Capital investment plan and average consolidated

rate base exclude NMGC. For more information

on the pending sale of NMGC,

refer to “Other Developments” section.

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

proceeds from the anticipated close of the NMGC transact

ion. Generally, Emera’s

equity requirements

are expected to be funded through the issuance of hybrid

securities, 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

19 consecutive years and has provided

annual dividend growth guidance of one to two per cent.

Emera anticipates average adjusted EPS growth

of five to seven per cent through 2030, using 2024 as the

base year, which will support

continued

reduction in the ratio of dividend payout to adjusted net

income over time. 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, 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 Items 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 2025 and 2024

Charges Related to the Pending Sale of NMGC:

On August 5, 2024, Emera entered into an agreement

to sell NMGC. In Q2 2025, the Company

recognized a $71 million non-cash impairment charge,

after-tax, and an additional loss of $1 million in

estimated transaction costs, after-tax, related to the pending

sale.

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 2024

Gain on Sale of Emera’s Indirect Minority Interest

in the Labrador Island Link (“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” section.

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” section.

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

Items Affecting Earnings” section.

Three months ended

Year ended

For the

December 31

millions of dollars (except per share amounts)

2025

2024

2025

2024

2023

Net income attributable to common shareholders

154

1,014

494

978

MTM (loss) gain, after-tax

(1)

(99)

(146)

(291)

169

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

(2)(3)

(72)

(225)

Gain on sale of LIL, after-tax

(4)

129

Financing structure wind-up

Charges related to wind-down costs and certain asset

impairments, after-tax

(5)

(26)

Adjusted net income

167

246

1,045

849

809

EPS – basic

0.23

0.52

3.39

1.71

3.57

Adjusted EPS – basic

0.55

0.84

3.49

2.94

2.96

(1) Net of income tax recovery of $39 million

for the three months ended December 31,

2025 (2024 – $57 million recovery) and $17

million expense for the year ended December 31,

2025 (2024 – $117 million recovery) (2023 – $68 million expense).

(2) Represents (i) $71 million non-cash impairment

charge, after-tax and $1 million in transaction

costs, after-tax for the year ended

December 31, 2025 and (ii) $206 million in non-cash

goodwill and other impairment charges,

after-tax and $19 million in transaction

costs, after-tax for the year ended December 31,

2024.

(3) Net of income tax recovery of $5 million for

the year ended December 31, 2025 (2024 –

$21 million).

(4) 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.

(5) Net of income tax recovery of $6 million for

the three months and year ended December 31,

2024.

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 absent the

income effect of MTM adjustments, charges related

to the pending sale of NMGC, the 2024 gain on sale

of LIL, and the 2024 charges related to wind-down costs

and certain asset impairments.

Reconciliation of Net Income to EBITDA and Adjusted EBITDA

Three months ended

Year ended

For the

December 31

millions of dollars

2025

2024

2025

2024

2023

Net income

(1)

173

1,090

568

1,045

Interest expense, net

268

248

1,032

973

925

Income tax (recovery) expense

(35)

(199)

(159)

128

Depreciation and amortization

335

296

1,294

1,162

1,049

EBITDA

655

518

3,497

2,544

3,147

MTM (loss) gain, excluding income tax

(138)

(203)

(408)

237

Charges related to the pending sale of NMGC,

excluding income tax

(77)

(246)

Gain on sale of LIL, excluding income tax

182

Charges related to wind-down costs and certain asset

impairments, excluding income tax

(32)

Adjusted EBITDA

793

753

3,516

3,048

2,910

(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”.

Earnings Impact of MTM (Loss) Gain, After-Tax

For Q4 2025, MTM loss, after-tax, decreased $47 million to

$99 million compared to $146 million in Q4

2024, primarily due to a gain on Corporate FX hedges compared

to a loss in prior year. For

the year

ended 2025, the 2024 MTM loss, after-tax, of $291

million decreased $332 million to a $41 million MTM

gain, after-tax primarily due to changes in existing positions

and lower amortization of gas transportation

assets at Emera Energy Services (“EES”) and a gain on Corporate

FX hedges compared to a loss in prior

year.

Charges Related to the Pending Sale of NMGC

2025:

In Q2 2025, Emera recognized a non-cash impairment

charge of $75 million ($71 million after-tax, or

$0.24 per common share) related to the remeasurement of the

NMGC disposal group to fair value (“FV”)

less costs to sell. This was recorded in “Impairment charges”

on the Consolidated Statements of Income

and included in the Other Segment.

2024:

In Q3 2024, Emera recognized non-cash goodwill and

other impairment charges of $221 million ($206

million 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.

Additionally, in Q3 2024,

Emera recorded a loss

of $24 million ($19 million after-tax, or $0.06 per common

share) in estimated transaction costs related to

the pending sale. These transaction costs were included

in “Other income, net” on the Consolidated

Statements of Income and included in the Other segment.

For further details on the pending sale of NMGC, refer to the “Other

Developments” section. For further

details on the non-cash impairment and goodwill charges,

refer to note 4 in the consolidated financial

statements.

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

expense (recovery)” on the Consolidated Statements of

Income in Q4 2024 and included in the Other

segment. For further details on the transaction, refer to

note 4 in the consolidated financial statements.

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 were expected to be

denied under the Excessive Interest and Financing Expenses

Limitation (“EIFEL”) legislation and, as a

result, the financing structure was wound up. It was determined

that Emera was 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 expense (recovery)” on the

Consolidated Statements of Income and included in the

Other segment during 2024.

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.

Consolidated Financial Highlights

For the

Three months ended

Year ended

millions of dollars

December 31

Adjusted net income

2025

2024

2025

2024

2023

Florida Electric Utility

119

120

845

644

627

Canadian Electric Utilities

182

232

247

Gas Utilities and Infrastructure

276

267

214

Other Electric Utilities

Other

(74)

(59)

(301)

(342)

(314)

Adjusted net income

167

246

1,045

849

809

MTM (loss) gain, after-tax

(99)

(146)

(291)

169

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

(72)

(225)

Gain on sale of LIL, after-tax

129

Financing structure wind-up

Charges related to wind-down costs and The following table highlights significant changes in adjusted net income from 2024 to 2025:

certain asset impairments, after-tax

(26)

Net income attributable to common shareholders

154

1,014

494

978

For the

Three months ended

Year ended

millions of dollars

December 31

Adjusted net income – 2024

246

849

Operating Unit Performance

Increased earnings at TEC year-over-year due to higher revenue from

new base rates, customer growth, favourable weather, and the impact of

a weaker CAD. These were partially offset by higher operating,

maintenance and general expenses ("OM&G"), depreciation, interest

expense, and income tax expense

(1)

201

Increased earnings at EES due to favourable weather conditions that led

to higher natural gas prices and increased volatility that created

profitable opportunities

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

OM&G. Increased earnings year-over-year due to higher revenue from

new base rates, partially offset by higher OM&G and depreciation

expense

(12)

Decreased income from equity investments due to the sale of LIL in Q2

2024

(28)

Decreased earnings at NSPI quarter-over-quarter primarily due to lower

income tax recovery due to the utilization of tax loss carryforwards

recognized as a deferred income tax regulatory liability in 2024. For both

quarter-over-quarter and year-over-year, decreased earnings due to

higher OM&G and higher depreciation expense, partially offset by higher

revenue due to favourable weather

(49)

(19)

Corporate

Increased interest expense due to increased Corporate debt and the

impact of a weaker CAD on USD interest expense, partially offset by

lower interest rates

(4)

(14)

Decreased income tax recovery due to decreased deferred income tax

asset valuation allowance adjustment

(27)

(9)

Other Variances

(3)

Adjusted net income – 2025

167

1,045

For the

Year ended December 31

millions of dollars

2025

2024

2023

Operating cash flow before changes in working capital

2,559

2,194

2,336

Change in working capital

(757)

452

(95)

Operating cash flow

1,802

2,646

2,241

Investing cash flow

(3,482)

(2,218)

(2,917)

Financing cash flow

1,841

(818)

939

For further discussion of cash flow,

refer to the "Consolidated Cash Flow Highlights"

section.

As at

December 31

millions of dollars

2025

2024

2023

Total

assets

44,817

42,951

39,480

Total

long-term debt (including current portion)

(1)

19,654

18,407

18,365

(1) Excludes NMGC balances classified as held

for sale at December 31, 2025 and December

31, 2024. 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)

2025

2024

Variance

2025

2024

Variance

2023

Operating revenues

2,006

1,763

243

8,776

7,200

1,576

7,563

Operating expenses

1,731

1,524

(207)

6,801

6,120

(681)

5,769

Income from operations

275

239

1,975

1,080

895

1,794

Other income (expense), net

(29)

165

203

(38)

158

Income tax (recovery) expense

(35)

(199)

(164)

(159)

(240)

128

Net income attributable to

common shareholders

154

(86)

1,014

494

520

978

Adjusted net income

167

246

(79)

1,045

849

196

809

Weighted average shares of

common stock outstanding

(in millions)

301.2

294.1

7.1

299.2

289.1

10.1

273.6

EPS – basic

0.23

0.52

(0.29)

3.39

1.71

1.68

3.57

EPS – diluted

0.25

0.52

(0.27)

3.38

1.71

1.67

3.57

Adjusted EPS – basic

0.55

0.84

(0.29)

3.49

2.94

0.55

2.96

Adjusted EBITDA

793

753

3,516

3,048

468

2,910

Dividends per common share

declared

0.7325

0.7250

0.0075

2.9075

2.8775

0.0300

2.7875

Dividends per first preferred shares declared:

Series A

0.7186

0.5456

0.1730

0.5456

Series B

0.9451

1.6966

(0.7515)

1.5583

Series C

1.6085

1.2873

Series E

1.1250

Series F

1.3406

1.0505

0.2900

1.0505

Series H

1.5810

1.3140

Series J

1.0625

Series L

1.1500

Trade Disputes and Tariffs

The extent of the future impact of trade disputes and tariffs

on the Company’s financial results and

business operations continues to evolve, cannot be predicted

at this time and will depend on future

developments. To

date, there has been no material financial impact on

the Company.

For information on

risks associated with trade disputes and the imposition of tariffs,

refer to the “Enterprise Risk and Risk

Management” section.

Operating Revenues

For Q4 2025, operating revenues increased $243 million

compared to Q4 2024 and, excluding decreased

MTM losses of $19 million, increased $224 million. The

increase was due to higher storm cost recoveries

at TEC and NSPI (offset in OM&G); new base rates

at TEC; and higher marketing and trading margin

EES.

For the year ended December 31, 2025, operating revenues

increased $1,576 million compared to 2024

and, excluding increased MTM gains of $369 million, increased

$1,207 million. The increase was due to

higher storm cost recoveries at TEC and NSPI (offset

in OM&G); new base rates at TEC and NMGC;

the

impact of a weaker CAD; higher fuel cost recoveries at

TEC, NSPI and NMGC; higher marketing and

trading margin at EES; and favourable weather at NSPI

and TEC.

Operating Expenses

For Q4 2025, operating expenses increased $207 million compared

to Q4 2024. Excluding charges

related to wind-down costs and certain asset impairments

of $4 million recognized in 2024, operating

expenses increased $211

million. For the year ended December 31, 2025, operating

expenses increased

$681 million compared to 2024. Excluding the change

in the charges related to the pending sale of

NMGC of $146 million and charges related to wind-down

costs and certain asset impairments of $4

million recognized in 2024, operating expenses increased $831

million. These increases were primarily

due to higher storm cost recognition of $97 million quarter

-over-quarter and $350 million year-over-year at

TEC and NSPI (offset in revenue); higher OM&G

at NMGC and NSPI; and increased depreciation

expense at TEC, PGS and NMGC. The year-over-year

increase was also due to higher natural gas prices

at TEC, PGS and NMGC; higher regulated fuel for generation

and purchase power at NSPI; and the

impact of a weaker CAD.

Other Income, net

For Q4 2025, other income, net increased $59 million compared

to Q4 2024, due to decreased FX losses

and the 2024 charges related to wind-down costs and

certain asset impairments.

For the year ended December 31, 2025, other income, net

decreased $38 million compared to 2024, due

to the gain on sale of LIL in 2024, partially offset

by higher FX gains in 2025, the 2024 charges related

wind-down costs and certain asset impairments and the

2024 transaction costs related to the pending

sale of NMGC.

Income Tax Expense

(Recovery)

For Q4 2025, income tax recovery decreased $164 million compared

to Q4 2024, due to the recognition

of tax benefits associated with denied interest and financing

expenses in the prior year,

decreased

deferred income tax asset valuation allowance adjustment

and increased income before provision for

income taxes.

For the year ended December 31, 2025, income tax expense

increased $240 million compared to 2024,

due to increased income before provision for income taxes

(excluding the gain on sale of LIL recognized

in 2024 and the charges related to the pending sale of NMGC),

recognition of tax benefits associated with

denied interest and financing expenses in the prior year,

and decreased deferred income tax asset

valuation allowance adjustment. These were partially offset

by the tax impact on the gain on sale of LIL

recognized in 2024 and increased tax credits recognized at

NSPI and TEC.

Net Income and Adjusted Net Income

Net income attributable to common shareholders for Q4 2025, compared

to Q4 2024, was favourably

impacted by the $47 million decrease in MTM losses, the

$26 million charges related to wind-down costs

and certain asset impairments in 2024, and unfavourably

impacted by the $58 million tax benefit related

to a specific financing structure and its wind-up recognized

in 2024 and the $22 million valuation

allowance reversal related to the gain on sale of LIL recognized

in 2024. Excluding these changes,

adjusted net income decreased $69 million due to decreased

earnings at NSPI and NMGC; and

increased Corporate costs. These were partially offset

by increased earnings at EES.

Net income attributable to common shareholders for the year

ended 2025, as compared to the same

period in 2024, was favourably impacted by the $332

million decrease in MTM losses, the $153 million

change in the charges related to the pending sale of NMGC,

and the $26 million in charges related to

wind-down costs and certain asset impairments and unfavourably

impacted by the $129 million gain on

sale of LIL recognized in 2024 and the $58 million tax benefit related

to a specific financing structure and

its wind-up recognized in 2024. Excluding these changes,

adjusted net income increased $206 million.

The increase was primarily due to increased earnings at TEC,

EES and NMGC. These were partially

offset by lower equity earnings from LIL; higher Corporate

costs; and lower earnings at NSPI.

EPS and Adjusted EPS – Basic

For Q4 2025, EPS - basic and adjusted EPS were lower

than Q4 2024 due to the impact of lower

earnings as discussed above and the impact of an increase

in weighted average shares outstanding.

For the year ended December 31, 2025, EPS – basic and

adjusted EPS were higher than 2024 due to the

impact of higher earnings as discussed above, partially offset

by the impact of an increase in weighted

average shares outstanding.

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 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 2025

and 2024 are as follows:

Three months ended

Year ended

December 31

2025

2024

2025

2024

Weighted average CAD/USD

1.36

1.37

1.41

1.36

Period end CAD/USD exchange rate

1.37

1.44

1.37

1.44

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

2025

2024

2025

2024

Florida Electric Utility

607

470

Gas Utilities and Infrastructure

(1)(2)

179

178

Other Electric Utilities

Other segment

(3)

(26)

(33)

(123)

(131)

Total

(2)(4)

120

123

694

552

(1) Includes USD net income from PGS, NMGC, SeaCoast

and M&NP.

(2) Excludes $6 million USD, after-tax, in other impairment

charges associated with the pending sale of

NMGC for the year ended

December 31, 2024.

(3) Includes Emera Energy's USD adjusted net income

from EES, Bear Swamp and interest expense

on Emera Inc.'s USD

denominated debt.

(4) Excludes $73 million USD in MTM losses, after-tax,

for the three months ended December 31, 2025

(2024 – $84 million USD

MTM losses, after-tax) and $5 million in USD

MTM gain, after-tax, for the year ended December

31, 2025 (2024 – $189 million USD

MTM losses, after-tax).

In Q4 2025, the translation impact of a stronger CAD on USD

denominated earnings decreased adjusted

net income by $3 million and decreased net income attributable

to common shareholders by $3 million,

compared to the same period in 2024. For the year ended December

31, 2025, the impact of a weaker

CAD on US denominated earnings increased adjusted net

income by $13 million and increased net

income attributable to common shareholders by $49 million, compared

to 2024. Impacts of the changes in

the translation of the CAD include the impacts of Corporate FX

hedges used to mitigate translation risk of

USD earnings

in the Other segment.

BUSINESS OVERVIEW AND OUTLOOK

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. With $14.5 billion USD of assets and approximately

866,000 customers at December 31, 2025,

TEC owns 6,771 megawatts (“MW”) of generating capacity,

of which 78 per cent is natural gas fired, 21

per cent is solar and 1 per cent is energy storage. TEC

owns approximately 2,200 kilometres of

transmission facilities and 21,100 kilometres of distribution

facilities. TEC meets the planning criteria for

reserve capacity established by the FPSC, which is a 20 per

cent reserve margin over firm peak demand.

TEC’s approved regulated ROE range is 9.50 per cent

to 11.50 per cent

based on an allowed equity

capital structure of 54 per cent. An ROE of 10.50 per cent

is used for the calculation of the return on

investments for clauses.

TEC anticipates earning within its allowed ROE range in 2026. USD

earnings are expected to be higher in

2026 than 2025 as a result of new base rates effective

January 1, 2026, and continued customer growth.

On September 4, 2025, TEC petitioned the FPSC to increase

base revenue by $88 million USD to reflect

the 2026 adjustment in accordance with its 2024 rate case

decision. On November 4, 2025, the FPSC

approved the adjustment, with new rates effective

January 1, 2026.

On February 3, 2025, the FPSC issued the final order approving

the 2024 rate case decision, effective

January 1, 2025. For additional details on the 2024 rate case, refer

to note 7 in Emera’s consolidated

financial statements. In February 2025, a motion for reconsideration

on certain aspects of the final order

was filed by an intervening party with the FPSC. On May

6, 2025, the FPSC denied the motion for

reconsideration, except with respect to immaterial calculation

corrections, and the final order was issued

on June 11, 2025.

In March 2025, two intervening parties each filed a

notice of appeal to the Florida

Supreme Court regarding the outcome of TEC’s

2024 base rate proceeding. On January 12, 2026, the

intervening parties filed their briefs related to the appeal.

date, the FPSC has not responded to the

briefs.

On February 4, 2025, the FPSC approved TEC’s

petition for the recovery of $466 million USD of 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, which began in

March 2025. The amount of cost-recovery is subject

to a true-up mechanism with the FPSC. For

additional details on the storm reserve, refer to note 7 in

Emera’s consolidated financial statements.

In 2026, capital investment in the Florida Electric Utility

segment is expected to be $1.8 billion USD (2025

– $1.6 billion USD), including allowance for funds used during construction

(“AFUDC”). Capital projects

include investment in generation reliability projects and

storm hardening, grid modernization, and

transmission expansion.

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.

NSPI

With $8.1 billion of assets and approximately 565,000 customers

at December 31, 2025, 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 2025, NSPI began operations

of two 50 MW grid-scale battery facilities to

enhance reliability.

In addition, NSPI has contracts to purchase renewable

energy from independent

power producers (“IPPs”) and community feed-in tariff

(“COMFIT") participants, which own 573 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, as discussed below.

NSPI

owns approximately 5,400 kilometres of transmission facilities

and 28,700 kilometres of distribution

facilities.

NLH is obligated to provide NSPI with approximately 900 Gigawatt

hours (“GWh”) of energy annually over

35 years. In addition, until March 31, 2026, 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.

Assuming new base rates are approved by the NSEB

in the general rate application (“GRA”) and are

generally consistent with the settlement agreement,

NSPI anticipates earning at the low end of its allowed

ROE in 2026 and expects earnings in 2026 to be higher

than 2025. Sales volumes are expected to be

higher in 2026 than 2025.

On September 18, 2025, NSPI filed a consensus GRA with

the NSEB, reflecting a settlement agreement

reached with customer representatives. The GRA proposes

average annual rate increases of 1.8 per cent

in 2026 and 2.4 per cent in 2027. The proposed rates

would result in annual revenue (fuel and non-fuel)

increases of $62 million in 2026 and $108 million in 2027. The

hearing for the matter concluded in

January 2026 and a decision by the NSEB is expected

by early Q2 2026.

On March 5, 2025, NSPI, the Canada Infrastructure Bank

(“CIB”) and the Wskijinu’k Mtmo’taqnuow

Agency (“WMA”) announced the Wasoqonatl

transmission line project to create a reliability intertie

between Nova Scotia and New Brunswick. The project

is owned by a new regulated utility,

WTI, which is

wholly-owned by a newly formed limited partnership between

NSPI, CIB and WMA. NSPI is responsible

for providing construction, operation, maintenance and administrative

services to WTI. NSPI has a 50 per

cent indirect voting interest in WTI which is recorded as

an “Investments subject to significant influence”

on Emera’s Consolidated Balance Sheets.

In 2026, capital investment is expected to be $720 million

(2025

– $712

million), including AFUDC. NSPI

is primarily investing in capital projects required to support power

system reliability and reliable service for

customers.

Environmental Legislation and Regulations

NSPI is subject to environmental laws and regulations set

by both the Government of Canada and the

Province of Nova Scotia (the “Province”). NSPI continues

to work with both levels of government to

comply with these laws and regulations to maximize efficiency

of emission control measures and

minimize customer cost. NSPI anticipates that costs prudently

incurred to achieve legislated compliance

will be recoverable under NSPI’s regulatory

framework. NSPI faces risks associated with achieving

climate-related and environmental legislative requirements, including

the risk of non-compliance, which

could adversely affect NSPI’s operations

and financial performance. For further discussion on these

risks

and environmental legislation and regulations, refer to

the “Enterprise Risk and Risk Management”

section. Recent developments related to provincial and federal environmental

laws and regulations are

outlined below.

Nova Scotia Energy Reform Act:

On October 15, 2025, the Nova Scotia Independent

Energy System Operator (“IESO Nova Scotia”)

announced that the organization will be phased in over

two phases during an 18-month period. On

December 1, 2025, the first phase was complete following

the transfer of system planning and

interconnection functions. The second phase is expected

to be complete in 2027 as IESO Nova Scotia

assumes responsibility for system operations. The establishment

of IESO Nova Scotia follows Bill 404 -

Energy Reform (2024) Act enacted in April 2024, which established

the NSEB, and phased transition to

IESO Nova Scotia.

Renewable Energy Regulations (“RER”):

On May 26, 2023, NSPI initiated an appeal, through a

proceeding with the NSEB, of the $10 million

penalty levied on NSPI by the Province for non-compliance

with the RER compliance period ending in

2022. The hearing concluded in 2025 and NSPI is awaiting

a decision.

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 2026 are expected to

be consistent with 2025. 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 will be delivered over the next 35

years pursuant to the project agreements.

On December 23,

2025, NSPML received an interim order from the

NSEB to collect up to $199 million

from NSPI for the recovery of costs associated with the

Maritime Link in 2026, subject to a monthly

holdback of up to $4 million.

A final decision from the NSEB is pending. There was

no holdback recorded

for the year ended December 31, 2025.

On February 4, 2026, NSPML submitted an application with

the NSEB requesting the termination of the

holdback mechanism. A decision is anticipated in Q3

2026.

In 2026, the capital investment at NSPML is expected to

be approximately $40 million (2025 – $7 million).

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. As a result of the pending sale,

NMGC’s assets and liabilities were classified as held

for sale as of Q3 2024. The public hearing was held

in November 2025. The transaction is expected to close in

the first half of 2026. For more information on

the pending transaction, refer to the “Other Developments”

section.

PGS

With $3.3 billion USD of assets and approximately 523,000 customers,

the PGS system includes

approximately 25,600 kilometres of natural gas mains and

14,800 kilometres of service lines. Natural gas

throughput (the amount of gas delivered to its customers,

including transportation-only service) was 2

billion therms in 2025.

Beginning in 2026, the approved ROE range for PGS is

9.30 per cent to 11.30

per cent (2025 – 9.15 per

cent to 11.15 per cent)

based on an allowed equity capital structure of 54.7

per cent (2025 – 54.7 per

cent). An ROE of 10.30 per cent (2025 – 10.15 per cent)

is used for the calculation of return on

investments for clauses.

PGS anticipates earning within its allowed ROE range

in 2026. USD earnings are expected to be higher

in 2026 than 2025, as a result of new base rates effective

January 1, 2026, and continued customer

growth.

On March 31, 2025, PGS filed a rate case with the FPSC

for new rates to become effective January

2026. On August 13, 2025, PGS and the intervening parties

filed a settlement agreement with the FPSC

for a $67 million USD increase in 2026 annual base rates,

which includes $7 million USD from the cast

iron and bare steel replacement rider,

and additional adjustments of $25 million USD in 2027

and up to $5

million USD in 2028 (subject to FPSC approval). This reflects

a 10.30 per cent midpoint ROE and 54.7

per cent equity thickness. On October 31, 2025, the FPSC

issued the final order approving the

settlement.

In 2026, capital investment is expected to be approximately

$445 million USD (2025 – $323 million USD),

including AFUDC. PGS will make investments to maintain the reliability

of their systems and support

customer growth.

NMGC

With $1.6 billion USD of assets and approximately 553,000 customers,

NMGC’s system includes

approximately 2,300 kilometres of transmission pipelines

and 18,200 kilometres of distribution pipelines.

Annual natural gas throughput was approximately 1 billion

therms in 2025.

The approved ROE for NMGC is 9.375 per cent, on an

allowed equity capital structure of 52 per cent.

NMGC’s USD earnings contribution to Emera in 2026

are expected to be lower than in 2025 as a result of

the pending sale of NMGC, which is expected to close in the first

half of 2026.

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

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 2026 are expected

to be consistent with the prior year.

In 2026, capital investment in the Other Electric Utilities

segment is expected to be approximately $110

million USD (2025 – $67 million USD), including AFUDC,

primarily in more efficient and cleaner sources

of generation, including renewables and battery storage.

BLPC

With $547 million USD of assets and approximately 137,000

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

200 kilometres of transmission facilities and 4,000 kilometres

of distribution facilities. BLPC’s approved

regulated return on rate base is 10 per cent.

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 was

heard in December 2025, and will continue in early 2026.

A decision is expected in 2026.

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 November 2025, the Government of Barbados

and BLPC agreed to new Transmission, Distribution,

Sales and Dispatch (“T&D”) and Generation and

Energy Storage (“G&S”) licenses. The G&S

license will be valid until 2047, unless otherwise extended.

The T&D License will be valid for 30 years. These new

non-exclusive licenses have since been signed

and will become effective upon the repeal of the

existing license. BLPC continues to operate under its

current statutory authority while preparing for the transition to

the new licensing framework.

GBPC

With $378 million USD of assets and approximately 20,000

customers, GBPC owns 98 MW of oil-fired

generation, approximately 100 kilometres of transmission

facilities and 1,000 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. A review of the proposal

by the GBPA

is expected to commence in the

first half of 2026.

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 (“URCA”), another

Bahamian regulator, regulate

GBPC. In 2024, URCA filed a claim in the Supreme

Court of the Bahamas,

seeking an order that the GBPA

be prohibited and restrained from considering and/or

approving any

adjustment to rates sought by GBPC. URCA contends that

it has regulatory authority over electricity

provision on Grand Bahama pursuant to the Electricity Act. Management

does not expect that the

outcome of the 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 Emera’s subsidiaries and investments.

Business operations in the Other segment include Corporate;

Emera Energy Services (“EES”), a physical

energy marketing and trading business; and a 50 per cent

joint venture interest in Bear Swamp, a 660

MW pumped storage hydroelectric facility in northwestern

Massachusetts.

Corporate includes

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.

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 million USD to $30 million

USD. In light of strong market conditions in

early 2026, EES expects USD adjusted net income for

2026 to be in line with 2025 results.

The adjusted net loss from the Other segment in 2026

is expected to be consistent with 2025.

In 2026, capital investment is expected to be approximately

$10 million (2025 – $6 million).

CONSOLIDATED

BALANCE SHEET HIGHLIGHTS

Significant changes in the Consolidated Balance Sheets between

December 31, 2024 and December 31,

2025 include:

Total

Increase

millions of dollars

(Decrease)

Explanation of Increase (Decrease)

Assets

Cash and cash equivalents

153

Increased due to higher cash from operations, increased

proceeds under committed credit facilities at TEC, proceeds from

debt issuances at TEC, and proceeds from common shares

issued. These were partially offset by investment in property,

plant and equipment ("PP&E"), repayment of committed credit

facilities at TECO Finance, Inc. ("TECO Finance") and Emera,

and dividends paid on Emera common stock

Regulatory assets (current and long-

term)

(229)

Decreased due to lower storm cost recovery assets at TEC and

NSPI and the effect of FX translation of Emera's non-Canadian

affiliates. These were partially offset by higher deferrals related to

the fuel adjustment mechanism ("FAM") and the deferred income

tax regulatory asset at NSPI

Receivables and other assets

(current and long-term)

984

Increased trade receivables due to higher commodity prices at

EES, higher trade receivables at NSPI and TEC, higher right of

use assets related to new finance leases at TEC, and increased

pension assets due to higher return on assets in 2025 at TEC

Assets held for sale (current and

long-term), net of liabilities

(1)

(101)

Decreased primarily due to non-cash impairment charge

recognized in 2025, and the effect of FX translation of NMGC

PP&E, net of accumulated

depreciation and amortization

1,240

Increased due to capital additions in excess of depreciation,

partially offset by the effect of FX translation of Emera's non-

Canadian affiliates

Goodwill

(278)

Decreased due to the effect of FX translation of Emera's non-

Canadian affiliates

Liabilities and Equity

Short-term debt and long-term debt

(including current portion)

1,654

Increased due to issuance of long-term debt at EUSHI Finance

Inc. ("EUSHI Finance") and TEC, proceeds from the issuance of

a non-revolving term credit facility at NSPI, and higher utilization

of committed credit facilities at TEC. These were partially offset

by the effect of FX translation of Emera's non-Canadian affiliates

and repayment of committed credit facilities at Corporate and

TECO Finance

Deferred income tax liabilities, net of

deferred income tax assets

156

Increased due to tax deductions in excess of accounting

depreciation related to PP&E and changes in pension and post-

retirement assets and liabilities. This was partially offset by

increased tax credits at TEC and the effect of FX translation of

Emera's non-Canadian affiliates

Regulatory liabilities (current and

long-term)

(211)

Decreased due to lower FAM liability at NSPI, lower cost recovery

clause liabilities and lower deferred income tax regulatory

liabilities at TEC, and the effect of FX translation of Emera's non-

Canadian affiliates

Other liabilities (current and long-

term)

Increased due to finance leases entered into at TEC and timing of

interest payments at Corporate

Common stock

345

Increased due to shares issued

Accumulated other comprehensive

income

(388)

Decreased due to the effect of FX translation of Emera's non-

Canadian affiliates, partially offset by higher unrecognized

pension and post-retirement benefit costs due to higher

investment returns and favourable changes in actuarial

assumptions and amortization at NSPI

Retained earnings

146

Increased due to net income in excess of dividends paid

(1) On August 5, 2024, Emera announced

the sale of NMGC. As a result, NMGC's

assets and liabilities were classified

as held for sale

beginning in Q3 2024. For further details, refer

to the "Other Developments" section and

note 4 in the consolidated financial statements.

OTHER DEVELOPMENTS

Increase in Common Dividend

On September 25, 2025, the Emera Board of Directors

approved an increase in the annual common

share dividend rate to $2.93 from $2.90 per common share.

The first payment was effective November

14, 2025.

Cybersecurity Incident

On April 25, 2025, Emera and NSPI discovered a cybersecurity

incident involving unauthorized access

into certain parts of its Canadian IT network and servers

supporting portions of its business applications

(the “Cybersecurity Incident’).

There was no disruption to the Canadian physical operations

or Emera’s

US or Caribbean utilities’ operations.

The Company implemented business continuity processes

for certain impacted business and

administrative functions at its Canadian affiliates. The

systematic restoration of affected IT systems and

corresponding transition away from business continuity processes

continues to progress in a planned,

controlled and phased approach. For more information on the

impact on internal controls over financial

reporting, refer to the “Disclosure and Internal Controls”

section. The Company maintains cyber insurance

coverage and is working with its insurer on the claims

process. At this time, the Cybersecurity Incident is

not expected to have a material impact on the Company’s

financial position or results of operations. For

information on risks associated with cybersecurity incidents

generally, refer

to the “Enterprise Risk and

Risk Management”

section.

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.

As a result of the pending sale, NMGC’s assets

and

liabilities were classified as held for sale in Q3 2024 and

the carrying value of the assets and liabilities

were adjusted to FV less cost to sell. The public hearing was

held in November 2025. The transaction is

expected to close in the first half of 2026.

At each reporting date, the Company performs an assessment of

the FV of the disposal group by

comparing the FV of expected transaction proceeds, less

costs to sell, to the carrying value of net assets,

including goodwill ("carrying amount"). On June 30, 2025, the

Company remeasured the NMGC disposal

group at the lower of its carrying amount and FV less costs

to sell. As a result of the change in the

expected timing of the transaction close, a non-cash impairment

charge of $75 million ($71 million, after-

tax), or $55 million USD ($52 million USD, after-tax), was

recorded in “Impairment charges” on the

Consolidated Statements of Income in Q2 2025. An additional

loss for estimated future transaction costs

of $2 million ($1 million after-tax) was recorded in “Other

income, net” on the Consolidated Statements of

Income in Q2 2025. There were no additional adjustments recorded

in 2025.

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 $97 million ($70 million USD) was

recorded on these assets from August 5, 2024, the date

they were classified as held for sale, through

December 31, 2025. Of the $97 million ($70 million USD)

recorded to date, $71 million ($51 million USD)

was recorded in 2025.

US One Big Beautiful Bill Act (“OBBBA”)

On July 4, 2025, the OBBBA was signed into law.

The OBBBA makes permanent many of the expired

and expiring tax provisions originally enacted in the Tax

Cuts and Jobs Act of 2017. It also includes

significant changes in future years to the timing and availability

of several clean energy tax credits

previously enacted in the Inflation Reduction Act, including

the investment tax credit and production tax

credit. On August 15, 2025, the Internal Revenue Service

released guidance on determining when wind

and solar projects have begun construction for purposes

of qualifying for these tax credits. Emera’s

2025

financial statements were not materially impacted as a

result of the enacted changes.

Emera will continue

to evaluate the future impact as additional information

and guidance becomes available.

New York Stock

Exchange (“NYSE”) Listing

Emera filed a registration statement dated May 1, 2025

on Form 40-F with the US Securities and

Exchange Commission (“SEC”) to register its common

shares under Section 12 of the Securities

Exchange Act of 1934. Emera subsequently completed

the listing of its common shares on the NYSE and

commenced trading on May 28, 2025. Emera’s

common shares continue to be listed and traded on

the

Toronto

Stock Exchange.

Appointments

Executive

Effective March 1, 2026, Vivek

Sood will become President and CEO of NSPI, succeeding

Peter Gregg.

Most recently, Mr.

Sood retired as Executive Vice President, Related

Businesses from Sobeys Inc. in

2024, and has served as a member of the NSPI Board

of Directors since June 2024.

Effective December 1, 2025, Jared Green became

Emera’s new Chief Financial Officer,

succeeding Greg

Blunden. Mr. Green most recently

served as President and Chief Executive Officer

of TriSummit Utilities

(previously AltaGas Canada).

Board of Directors

Effective September 17, 2025, Isabelle Courville joined

the Emera Board of Directors. Ms. Courville is

Chair of the Board of Canadian Pacific Kansas City and

previously served as President of Hydro-Québec

Distribution and Hydro Québec TransÉnergie,

as well as President of Bell Canada’s Enterprise

Group.

FINANCIAL HIGHLIGHTS

Florida Electric Utility

Three months ended

Year ended

For the

December 31

millions of USD (except as indicated)

2025

2024

2025

2024

Operating revenues – regulated electric

706

582

3,115

2,526

Regulated fuel for generation and purchased power

150

151

703

622

Contribution to consolidated adjusted net income

607

470

Contribution to consolidated adjusted net income - CAD

119

120

845

644

Charges related to wind-down costs and certain asset

impairments, after-tax

(1)

(2)

Contribution to consolidated net income

607

468

Contribution to consolidated net income – CAD

119

117

845

641

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 FX rates on CAD earnings

was minimal for the three months ended

December 31, 2025, and increased CAD earnings by $16 million

for the year ended December 31, 2025.

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 – 2024

468

Increased operating revenues primarily due to storm cost recovery

revenue (offset in OM&G), new base rates, higher regulatory deferral

revenue and customer growth. These were partially offset by

unfavourable weather of $10 million quarter-over-quarter. Year

-over-

year increase was also due to favourable weather of $10 million

124

589

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

to higher natural gas prices and higher purchased power

(81)

Increased OM&G due to higher storm cost recognition (offset in

revenue), higher costs for employee benefits, operations related to

solar investments, and software maintenance. These were partially

offset by the timing of recognition of regulatory deferrals

(88)

(246)

Increased depreciation and amortization due to facilities and capital

projects placed in service

(17)

(51)

Increased interest expense due to higher borrowings

(9)

(25)

Increased state and municipal taxes due to higher revenues and higher

taxable plant in service

(10)

(28)

Increased income tax expense year-over-year primarily due to higher

income before provision for income taxes, partially offset by higher

benefit from production tax credits and increased amortization of

deferred investment tax credits

(32)

Other

(1)

Contribution to consolidated net income – 2025

607

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"))

2025

2024

2025

2024

Residential

1,786

1,507

10,309

10,269

Commercial

822

686

6,536

6,481

Industrial

195

162

2,105

2,019

Other

(1)

312

171

2,377

2,276

Total

3,115

2,526

21,327

21,045

(1) Other includes regulatory deferrals related

to clauses, sales to public authorities, and 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)

2025

2024

Natural gas

17,470

18,027

Solar

2,419

2,250

Purchased power

2,004

1,569

Coal

Total

21,939

21,878

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 incrementa

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

Three months ended

Year ended

For the

December 31

millions of dollars (except as indicated)

2025

2024

2025

2024

Operating revenues – regulated electric

504

479

1,944

1,855

Regulated fuel for generation and purchased power

(1)(2)

269

(216)

1,065

509

Contribution to consolidated net income

182

232

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) Regulated fuel for generation and purchased power

and average fuel costs for 2024 include a

$486 million refund of previous

NSPML assessment payments ("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. For more information on the NSPML Refund, 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

2025

2024

2025

2024

NSPI

141

160

Equity investment in NSPML

Equity investment in LIL

Contribution to consolidated net income

182

232

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 – 2024

232

Increased operating revenues at NSPI due to higher fuel and storm cost

recoveries, favourable weather, and increased residential and

commercial sales volumes, partially offset by lower industrial sales

volumes

Increased regulated fuel for generation and purchased power at NSPI

due to the 2024 NSPML Refund

(1)

, changes in generation mix, and

higher sales volumes, partially offset by lower commodity prices

(485)

(556)

Decreased FAM deferral at NSPI primarily due to the 2024 NSPML

Refund

(1)

472

511

Increased OM&G at NSPI quarter-over-quarter due to increased storm

costs and costs related to the Cybersecurity Incident. Year-over-year

increased due to higher costs for transmission and distribution

operations, costs related to the Cybersecurity Incident and power

generation operations, partially offset by higher administrative overhead

allocation to PP&E

(21)

(49)

Increased depreciation and amortization due to increased PP&E in

service

(4)

(16)

Decreased income from equity investments due to the sale of equity

interest in LIL

(28)

Decreased income tax recovery quarter-over-quarter at NSPI primarily

due to the utilization of tax loss carryforwards recognized as a deferred

income tax regulatory liability in the prior year and decreased tax

deductions in excess of accounting depreciation related to PP&E

(35)

Other

(5)

Contribution to consolidated net income – 2025

182

(1) For more information on the $486 million

NSPML Refund in 2024, 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)

2025

2024

2025

2024

Residential

1,073

997

5,292

5,096

Commercial

522

499

3,084

3,046

Industrial

270

276

2,098

2,217

Other

231

222

Total

1,908

1,813

10,705

10,581

Regulated Fuel for Generation and Purchased Power

Annual production volumes are summarized in the following table:

Production Volumes (GWh)

2025

2024

Coal

4,370

3,347

Natural gas

1,403

2,317

Purchased power

391

620

Oil

295

132

Petcoke

279

374

Total

non-renewables

6,738

6,790

Purchased power - IPP,

COMFIT and imports

3,707

3,464

Wind, hydro and solar

855

932

Biomass

174

140

Total

renewables

4,736

4,536

Total

production volumes

11,474

11,326

NSPI’s fuel costs are affected by commodity

prices and generation mix, which is largely dependent

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 NSEB 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 of Nova Scotia (“Public Utilities Act”) and is

subject to regulation by the NSEB. The Public Utilities

Act gives the NSEB supervisory powers over

NSPI’s operations and expenditures. 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 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 NSEB’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. As a result of the pending sale,

NMGC’s assets and liabilities were classified as held

for sale beginning in Q3 2024. The public hearing

was held in November 2025. The transaction is expected to

close in the first half of 2026, 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)

2025

2024

2025

2024

Operating revenues – regulated gas

(1)

327

317

1,235

1,160

Operating revenues – non-regulated

Total

operating revenue

331

320

1,252

1,175

Regulated cost of natural gas

318

289

Contribution to consolidated adjusted net income

196

194

Contribution to consolidated adjusted net income – CAD

276

267

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

(2)

(6)

Contribution to consolidated net income

196

188

Contribution to consolidated net income – CAD

276

259

(1) Operating revenues – regulated gas includes $12

million of finance income from Brunswick Pipeline

(2024 – $12 million) for the

three months ended December 31, 2025 and $46

million (2024 – $46 million) for the year ended December

31 2025; 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 $2 million for the

year ended December 31, 2024.

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

2025

2024

2025

2024

PGS

117

120

NMGC

Other

Contribution to consolidated adjusted net income

196

194

The impact of the change in FX rates on CAD earnings

was minimal for the three months ended

December 31, 2025, and increased CAD earnings by $7 million

for the year ended December 31, 2025.

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 – 2024

188

Increased gas revenues due to higher fuel revenue and higher off-

system sales at PGS and new base rates at NMGC

Decreased cost of natural gas quarter-over-quarter primarily due to

timing of profit sharing with customers related to asset management

agreements at NMGC. Increased cost of natural gas year-over-year

due to higher natural gas prices at PGS

(29)

Increased OM&G primarily due to higher labour costs at NMGC

(16)

(20)

Increased depreciation primarily due to capital projects in service at Operating Revenues – Regulated Gas

PGS and NMGC

(4)

(14)

Other

(5)

(6)

Contribution to consolidated net income – 2025

196

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)

2025

2024

2025

2024

Residential

548

520

394

410

Commercial

377

362

875

824

Industrial

(1)

1,568

1,620

Other

(2)

191

163

313

278

Total

(3)

1,189

1,114

3,150

3,132

(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

(2024 – $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)

2025

2024

Transportation

2,463

2,434

System supply

687

698

Total

3,150

3,132

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 or revenue requirements 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

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)

2025

2024

2025

2024

Operating revenues – regulated electric

102

107

413

Regulated fuel for generation and purchased power

211

215

Contribution to consolidated adjusted net income

Contribution to consolidated adjusted net income – CAD

Equity securities MTM loss

(1)

Contribution to consolidated net income

Contribution to consolidated net income – CAD

Electric sales volumes (GWh)

330

323

1,307

Electric production volumes (GWh)

345

347

1,390

1,403

Average fuel cost in dollars per MWh

148

159

152

153

The impact of the change in FX rates on CAD earnings

and adjusted net income for the three months and

year ended December 31, 2025 was minimal.

Other Electric Utilities' contribution to consolidated adjusted

net income is summarized in the following

table:

Three months ended

Year ended

For the

December 31

millions of USD

2025

2024

2025

2024

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 – 2024

Decreased operating revenues quarter-over-quarter due to lower fuel

revenue and lower miscellaneous revenue at BLPC

(5)

Decreased regulated fuel for generation and purchased power due to

lower fuel costs at BLPC and GBPC

Increased income tax expense year-over-year due to the 2025

remeasurement of deferred income tax liabilities as a result of a

corporate income tax rate change at BLPC

(2)

Increased depreciation and amortization expense at GBPC due to

increased generation units in service

(4)

(5)

Other

(1)

Contribution to consolidated net income – 2025

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

2025

2024

2025

2024

Marketing and trading margin

(1)(2)

158

Other non-regulated operating revenue

Total

operating revenues – non-regulated

190

109

Contribution to consolidated adjusted net (loss) income

(74)

(59)

(301)

(342)

MTM (loss) gain, after-tax

(3)

(97)

(144)

(291)

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

(4)

(72)

(217)

Gain on sale of LIL, after-tax

(5)(6)

129

Financing structure wind-up

Charges related to wind-down costs and certain asset

impairments, after-tax

(7)

(23)

Contribution to consolidated net (loss) income

(171)

(146)

(332)

(686)

(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 $144 million in Q4 2025 (2024

– $159 million loss) and a MTM

gain, pre-tax of $16 million for the year ended

December 31, 2025 (2024 – $357 million loss).

(3) Net of income tax recovery of $39 million

for the three months ended December 31,

2025 (2024 – $57 million recovery) and $17

million expense for the year ended December 31,

2025 (2024 – $117 million recovery).

(4) Includes an impairment charge of $75 million ($71

million after-tax) and transaction costs of $2 million

($1 million after-tax) for

the year ended December 31, 2025, and impairment

charges of $210 million ($198 million, after-tax)

and transaction costs of $25

million ($19 million after-tax) for the year ended

December 31, 2024.

(5) On June 4, 2024, Emera completed the sale

of its LIL equity interest. For further details

on the transaction, refer to note 4 in the

consolidated financial statements.

(6) Includes an income tax recovery of $22 million

for the three months ended December 31,

2024 and net income tax expense of

$53 million for the year ended December 31, 2024.

(7) Primarily relates to Block Energy, net of income tax recovery of $6

million for the year ended December 31, 2024.

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

2025

2024

2025

2024

Emera Energy:

EES

Other

(1)

(2)

(6)

Corporate – see breakdown below

(106)

(73)

(380)

(360)

Block Energy

(13)

Other

(1)

Contribution to consolidated adjusted net (loss) income

(74)

(59)

(301)

(342)

Net Income (Loss)

Highlights of net income (loss) 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 – 2024

(146)

(686)

Increased marketing and trading margin at EES due to favourable

weather conditions that led to higher natural gas prices and increased

volatility that created profitable opportunities

Decreased equity earnings at Bear Swamp due to lower generation as

a result of a prolonged unplanned outage

(3)

(17)

Increased interest expense primarily due to increased Corporate debt

and the impact of a weaker CAD on USD interest expense, partially

offset by lower interest rates

(4)

(14)

Decreased income tax recovery due to decreased loss before

provision for income taxes and decreased deferred income tax asset

valuation allowance adjustment

(31)

(26)

Decreased MTM loss, after-tax, due to a gain on Corporate FX

hedges compared to a loss in prior year. Year

-over-year also

decreased due to changes in existing positions and lower amortization

of gas transportation assets at EES

332

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

145

Gain on sale of LIL, after-tax in 2024

(22)

(129)

Financing structure wind-up in 2024

(58)

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

after-tax in 2024

Other

(2)

Contribution to consolidated net (loss) income – 2025

(171)

(332)

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.

In 2025, as a result of a strong Q1, EES adjusted its

annual earnings guidance range to $35 million USD

to $45 million USD. EES’ contribution to consolidated

adjusted net income was $33 million in Q4 2025,

compared to $16 million in Q4 2024; and $80 million ($57

million USD) for the year ended December 31,

2025, compared to $30 million ($21 million USD) for the same

period in 2024. Market conditions in 2025

were favourable compared to 2024 due to weather conditions which led to higher natural gas prices and Emera Energy’s “Marketing and trading margin”, “Income from equity investments” and “Income tax

volatility.

MTM Adjustments

expense (recovery)” 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

which 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

2025

2024

2025

2024

Operating expenses

(1)

(35)

(23)

(78)

(74)

Interest expense

(101)

(97)

(381)

(367)

Income tax recovery

160

170

Preferred dividends

(19)

(75)

(73)

Other

(2)(3)

(10)

(6)

(16)

Corporate adjusted net loss

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

(106)

(73)

(380)

(360)

(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 $4 million

($2 million after-tax) for the three months ended

December 31, 2025 (2024 – $5

million net loss, pre-tax and $4 million loss, after-tax)

and a $16 million net loss, pre-tax ($11 million after-tax) for the year

ended

December 31, 2025 (2024 – $12 million net loss,

pre-tax and $9 million loss after-tax) on FX hedges,

as discussed above.

(4) Excludes a MTM gain, after-tax of $5 million

for the three months ended December 31, 2025

(2024 – $25 million loss, after-tax)

and a MTM gain, after-tax of $28 million for

the year ended December 31, 2025 (2024 – $31

million loss, after-tax).

(5) Excludes a gain on sale of LIL, after-tax,

of $107 million for the year ended December

31, 2024.

(6) Excludes certain charges related to the pending

sale of NMGC of $77 million ($72 million after-tax)

for the year ended December

31, 2025 (2024 - $235 million, pre-tax and $217

million, after-tax).

(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.

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 2026 through 2030 period and

supports ongoing growth. Capital investments at Emera’s

regulated utilities are subject to regulatory

approval.

Emera has sufficient liquidity to service debt obligations

as they come due and 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 hybrid securities

and issuance of common equity through Emera’s

DRIP and ATM programs.

Emera has total committed credit facilities with varying

maturities that cumulatively provide $2.8 billion

CAD and $2.1 billion USD of credit, with approximately

$999 million CAD and $1,056 million USD

undrawn and available at December 31, 2025. The Company was

holding a cash balance of $355 million,

which includes $6 million classified as assets held for

sale, related to the pending sale of NMGC, at

December 31, 2025. 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, 2025 and 2024 include:

millions of dollars

2025

2024

Change

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

for sale, beginning of period

221

588

(367)

Provided by (used in):

Operating cash flow before changes in working capital

2,559

2,194

365

Changes in non-cash working capital

(757)

452

(1,209)

Operating activities

1,802

2,646

(844)

Investing activities

(3,482)

(2,218)

(1,264)

Financing activities

1,841

(818)

2,659

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

cash associated with assets held for sale

(11)

(34)

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

for sale, end of period

371

221

150

Cash Flow from Operating Activities

Net cash provided by operating activities decreased $844 million

to $1,802 million for the year ended

December 31, 2025, compared to $2,646 million in 2024.

Cash from operations before changes in working capital

increased $365 million for the year ended

December 31, 2025. This increase was due to higher

storm cost recoveries at TEC, new base rates at

TEC and NMGC, and higher marketing and trading margin at

EES. These were partially offset by

proceeds from the FAM asset

sale at NSPI in Q2 2024 and higher fuel under-recoveries

at TEC.

Changes in working capital decreased operating cash flows

by $1,209 million for the year ended

December 31, 2025. This decrease was due to unfavourable

changes in accounts payable at TEC

reflecting the timing and payment of storm invoices, unfavourable

changes in accounts receivable at TEC

due to increased base rates and storm cost recoveries,

and unfavourable changes in accounts receivable

and fuel inventory at NSPI. These were partially offset

by favourable changes in accounts receivable at

PGS.

Cash Flow Used in Investing Activities

Net cash used in investing activities increased $1,264 million to

$3,482 million for the year ended

December 31, 2025, compared to $2,218 million in 2024. The

increase was due to the proceeds of $927

million received in 2024 on the sale of LIL and higher capital

investment, partially offset by proceeds on

the disposal of assets.

Capital expenditures for the year ended December 31,

2025, including AFUDC, were $3,594 million

compared to $3,206 million in 2024. Details of capital spending

by segment are shown below:

●

$2,221 million – Florida Electric Utility (2024 – $1,998

million);

●

$648 million – Canadian Electric Utilities (2024 – $494 million);

●

$624 million – Gas Utilities and Infrastructure (2024 – $626

million);

●

$95 million – Other Electric Utilities (2024 – $81 million);

and

●

$6 million – Other (2024 – $7 million).

Cash Flow from Financing Activities

Net cash provided by financing activities increased $2,659

million to $1,841 million for the year ended

December 31, 2025, compared to net cash used in financing

activities of $818 million in 2024. The

increase was due to higher net borrowings on committed credit

facilities at NSPI and TEC, higher

proceeds from Corporate debt, proceeds from short-term

debt issuances at NSPI and NMGC, retirement

of long-term debt at TEC and NMGC in 2024 and higher

proceeds from long-term debt at TEC. These

were partially offset by lower proceeds from long-term

debt at PGS, lower issuance of common stock, and

retirement of long-term debt at NSPI.

Working Capital

As at December 31, 2025, Emera’s cash and cash

equivalents were $349 million (2024 – $196 million)

and Emera’s investment in non-cash working capital

was $926 million (2024 – $224 million). Of the cash

and cash equivalents held at December 31, 2025, $279 million

was held by Emera’s foreign subsidiaries

(2024 – $185 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 As at December 31, 2025, contractual commitments for each of the next five years and in aggregate

capital requirements unless repatriated.

Contractual Obligations

thereafter consisted of the following:

millions of dollars

2026

2027

2028

2029

2030

Thereafter

Total

Long-term debt principal

(1)(2)

1,297

321

763

1,824

554

15,702

20,461

Interest payment obligations

(3)(4)

971

933

925

851

800

14,718

19,198

Purchased power

(5)

413

422

411

459

451

5,941

8,097

Transportation

(6)(7)

780

588

478

413

370

2,954

5,583

Fuel, gas supply and storage

(8)

674

239

159

156

1,325

Pension and post-retirement

obligations

(9)

242

375

Asset retirement obligations

449

461

Capital projects

288

395

Other

144

294

651

4,601

2,669

2,850

3,786

2,281

40,359

56,546

As detailed below, contractual obligations at December 31, 2025 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 $663 million related to NMGC (2026:

$96 million, and $567 million thereafter).

(2) The Company’s $1.2 billion USD, $750 million USD

and $500 million USD hybrid notes mature

in 2076, 2056 and 2054,

respectively, and these maturity dates have been used in the computation

of the Company’s long-term debt principal and interest

payment obligations at December 31, 2025. The Company

has the option to repay such notes in advance

of maturity upon exercise

of the Company’s redemption rights in accordance

with the terms of the applicable indenture. Emera’s $1.2 billion

USD hybrid notes

are redeemable, at Emera’s option, in June 2026.

(3) 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, 2025, including any expected

required payment under associated swap agreements.

(4) Includes $311 million related to NMGC (2026: $25 million, 2027:

$22 million, 2028: $22 million, 2029: $22 million,

2030: $22

million, and $198 million thereafter).

(5) Annual requirement to purchase electricity from

IPPs or other utilities over varying contract lengths.

(6) Purchasing commitments for transportation of

fuel and transportation capacity on various pipelines.

Includes a commitment of

$121 million related to a gas transportation contract between

PGS and SeaCoast through 2040.

(7) Includes $61 million related to NMGC (2026: $23

million, 2027: $15 million, 2028: $12 million, 2029:

$3 million, 2030: $3 million

and $5 million thereafter).

(8) Includes $101 million related to NMGC (2026:

$86 million, 2027: $12 million and, 2028: $3

million).

(9) 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. On December

23, 2025, NSPML received an interim order from

the NSEB to collect up to $199 million from NSPI for the

recovery of costs associated with the Maritime

Link in 2026, subject to a monthly holdback of up to $4

million. The timing and amounts payable to

NSPML for the remainder of the 38-year commitment period

are subject to NSEB 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 The 2026 forecasted consolidated capital investments, including AFUDC, are as follows:

table.

Forecasted Consolidated Capital Investments

millions of dollars

Florida

Electric

Utility

Canadian

Electric

Utilities

Gas Utilities

and

Infrastructure

Other

Electric

Utilities

Other

Total

Generation

1,068

183

1,307

New renewable generation

Electric transmission

(1)

321

287

640

Electric distribution

767

195

997

Gas transmission and distribution

665

Facilities, equipment, vehicles, and other

274

404

2,430

760

670

150

4,020

(1) Electric transmission for the Canadian Electric Utilities

segment includes $40 million related to NSPML,

which is recorded as

"Investments subject to significant influence" on Emera's Consolidated

Balance Sheets.

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

523

777

NSPI – committed revolving credit facility

June 2029

800

578

222

NSPI – non-revolving facility

May 2026

500

Emera – non-revolving facility

February 2027

200

In USD:

TEC – committed revolving credit facility

November 2030

1,200

774

426

TECO Finance – committed revolving credit facility

November 2030

400

395

PGS – revolving facility

November 2030

250

145

105

NMGC – revolving credit facility

(1)

December 2027

125

109

NMGC – non-revolving facility

(1)

October 2026

Other – committed revolving credit facilities

Various

(1) On August 5, 2024, Emera announced an

agreement to sell NMGC. As a result,

NMGC's assets and liabilities were classified as

held for sale beginning in Q3 2024. For further details

on the pending transaction, refer to the

"Other Developments" section.

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, 2025.

Emera’s significant covenant is listed below:

As at

Financial Covenant

Requirement

December 31, 2025

Emera

Syndicated credit facilities

Debt to capital ratio

Less than or equal to 0.70 to 1

0.53 : 1

Recent significant financing activity for Emera and

its subsidiaries are discussed below by segment:

Florida Electric Utility

On November 20, 2025, TEC amended and restated its

$800 million USD committed revolving credit

facility to extend the maturity date from December 1, 2028,

to November 20, 2030 and increased the

amount to $1.2 billion USD. There were no other material

changes in commercial terms from the prior

agreement.

On March 6, 2025, TEC issued $600 million USD of senior

unsecured notes that bear interest at 5.15 per

cent with a maturity date of March 1, 2035. Proceeds from

this issuance were used for the repayment of a

portion of TEC’s outstanding commercial paper.

Canadian Electric Utilities

On May 21,

2025, NSPI entered into a $500 million non-revolving

facility which matures on May 21, 2026.

The credit agreement contains customary representations

and warranties, events of default and financial

and other covenants.

The non-revolving facility’s interest rates are referenced

to the Term

CORRA or

prime rate, plus a margin. Proceeds from this facility

were used for general corporate purposes.

Gas Utilities and Infrastructure

On November 20, 2025, PGS amended and restated its

$250 million USD unsecured committed revolving

credit facility to extend the maturity date from December

1, 2028, to November 20, 2030. There were no

other changes in commercial terms from the prior agreement.

On October 23, 2025, NMGC entered into a $70 million

USD, 364-day term loan agreement which

matures on October 22, 2026. The credit agreement contains

customary representations and warranties,

events of default and financial and other covenants. The non-revolving

facility’s interest rates are

referenced to the Term

SOFR plus a margin. Proceeds from this facility were used

for general corporate

purposes.

On September 19, 2025, NMGC amended its $125 million

USD unsecured committed revolving credit

facility to extend the maturity date from December 17,

2026, to December 17, 2027. There were no other

changes in commercial terms from the prior agreement.

Other

On February 20,

2026, Emera amended its $200 million unsecured

non-revolving facility to extend the

maturity date from February 20, 2026 to February 19,

2027. There were no other material changes to the

terms from the prior agreement.

On November 20, 2025, TECO Finance amended and

restated its $400 million USD unsecured

committed revolving credit facility to extend the maturity

date from December 1, 2028, to November 20,

2030. There were no other changes in commercial terms

from the prior agreement.

On September 25, 2025, EUSHI Finance, Emera US Holdings

Inc. (“EUSHI”) and Emera filed a shelf

registration statement on Form F-10 and Form F-3 (“Registration

Statement”), with the Nova Scotia

Securities Commission (“NSSC”) and the SEC under the US/Canada

Multijurisdictional Disclosure

System. The Registration Statement was filed in connection with

the prospective offer and issue by

EUSHI Finance of one or more series of senior and/or subordinated

unsecured debt securities (“Debt

Securities”), in an aggregate principal amount of up to

$3 billion USD, during the 25-month period that the

short form base shelf prospectus contained in the Registration

Statement (“Base Shelf Prospectus”),

including any further amendments thereto, remains valid.

The Debt Securities may be offered in one or

more transactions, at prices, with maturities and on terms

to be set forth in one or more prospectus

supplements to be filed with the NSSC and the SEC at the time

of any such offering.

On October 3, 2025, EUSHI Finance completed an issuance

of $750 million USD fixed-to-fixed reset rate

junior subordinated notes, pursuant to the prospectus

supplement dated September 29, 2025, to the

Base Shelf Prospectus. The notes initially bear interest

at a rate of 6.25 per cent, and will reset on April 1,

2031, and every five years thereafter,

to a rate per annum equal to the five-year US

treasury rate plus

2.509 per cent, subject to an interest rate floor of 6.25

per cent. The notes mature on April 1, 2056.

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, plus accrued and unpaid interest on the notes

to be redeemed, in accordance with the

terms of the prospectus supplement; and otherwise, at

the times and the redemption prices described in

the prospectus supplement.

The notes are fully and unconditionally guaranteed, on

a joint, several and

subordinated basis, by Emera, and EUSHI. Proceeds from this

issuance were used for general corporate

purposes, including repayment of existing debt.

On February 20, 2025, Emera amended its $200 million

unsecured non-revolving facility to extend the

maturity date from February 20, 2025 to February 20,

2026. There were no other material changes to the

terms from the prior agreement.

Credit Ratings

Emera and its subsidiaries have been assigned the following

senior unsecured debt ratings:

Fitch

S&P

Moody's

DBRS

Emera

(1)

BBB (Stable)

BBB- (Stable)

Baa3 (Negative)

N/A

TEC

(1)

A (Stable)

BBB+ (Stable)

A3 (Negative)

N/A

PGS

(1)

A (Stable)

N/A

NMGC

BBB+ (Stable)

N/A

NSPI

N/A

BBB- (Stable)

N/A

BBB (high)(stable)

(1) On May 27, 2025, Fitch Ratings ("Fitch") revised

its outlook on Emera, TEC and PGS to

stable from negative with no changes to

existing ratings.

Guaranteed Debt

As of December 31, 2025, the Company had $3.70 billion

USD (2024 – $2.95 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

and 2056, on a joint, several and

subordinated basis, by Emera and 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 The Company recognized income related to guaranteed debt under the following categories:

reporting.

Summarized Statement of Income

For the

Year ended December 31

millions of dollars

2025

2024

Loss from operations

(145)

(279)

Net gains

(1)

168

442

(1) Includes $1,143 million (2024 – $1,352 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

2025

2024

Current assets

(1)

373

391

Goodwill

5,580

5,858

Other assets

(2)

5,259

6,474

Total

assets

(3)

11,212

12,723

Current liabilities

(4)

1,587

611

Long-term liabilities

(5)

11,293

13,129

Total

liabilities

12,880

13,740

(1) Includes $275 million (2024 – $217 million) in

amounts due from non-guarantor subsidiaries.

(2) Includes $4,714 million (2024 – $5,937 million)

in amounts due from non-guarantor subsidiaries.

(3) Excludes investments in non-guarantor subsidiaries.

Consolidated Emera total assets are $44,817

million (2024 – $42,951 million).

(4) Includes $206 million (2024 – $184 million) due

to non-guarantor subsidiaries.

(5) Includes $4,609 million (2024 – $5,980 million)

due to non-guarantor subsidiaries.

Outstanding Stock Data

Common Stock

millions of

Issued and outstanding:

dollars

Balance, December 31, 2024

295.94

9,042

Conversion of Convertible Debentures

0.02

Issuance of common stock under ATM program

(1)

0.19

Issued under the DRIP,

net of discounts

4.83

293

Senior management stock options exercised and Employee Share Purchase Plan

0.78

Balance, December 31, 2025

301.76

9,387

(1) For the year ended December 31, 2025, a

total of 187,600 common shares were issued

under Emera's ATM program at an

average price of $53.58 per share for gross proceeds

of $10 million ($9 million, net of after-tax

issuance costs). As at December 31,

2025, an aggregate gross sales limit of $600

million remained available for issuance under

the ATM program.

As at February 18, 2026, the amount of issued and outstanding

common shares was 303.0 million.

If all outstanding stock options were converted as at February

18, 2026, an additional 4.1 million common

shares would be issued and outstanding.

ATM Equity Program

On December 5, 2025, Emera renewed its ATM

Program by filing a prospectus supplement to the

Company's Canadian short form base shelf prospectus

with the securities regulatory authorities in each of

the provinces of Canada. At the same time, Emera filed a US

prospectus supplement to the Company’s

US base prospectus included in its US registration statement

on Form F-10 with the SEC. The ATM

Program 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 is

expected to remain in effect until January 5, 2029.

Preferred Stock

As at February 18, 2026, Emera had the following preferred

shares issued and outstanding: Series A –

6.0 million; Series C – 10.0 million; Series E – 5.0 million;

Series F – 8.0 million; Series H – 12.0 million;

Series J – 8.0 million, and Series L – 9.0 million. Emera’s

preferred shares do not have voting rights

unless the Company fails to pay,

in aggregate, eight quarterly dividends.

On July 9, 2025, Emera announced it would not redeem the

currently outstanding Cumulative 5-Year

Rate Reset Preferred Shares, Series A (“Series A Shares”)

or the Cumulative Floating Rate First

Preferred Shares, Series B (“Series B Shares”) on August 15,

2025 (the “Conversion Date”).

On July 16, 2025, Emera announced a dividend rate of 4.951 per

cent per annum on the Series A Shares

during the five-year period commencing on August 15,

2025 and ending on (and inclusive of) August 14,

2030 ($0.3094 per Series A Share per quarter).

During the conversion period between July 16, 2025 and July

31, 2025, the holders of Series A Shares

had the right, at their option, to convert all or any of their

Series A Shares, on a one-for-one basis, into

Series B Shares and the holders of Series B Shares had the

right, at their option, to convert all or any of

their Series B Shares, on a one-for-one basis, into Series

A Shares. On August 7, 2025, Emera

announced, after having taken into account all shares

tendered for conversion by holders of its Series A

Shares and Series B Shares, as the case may be (collectively,

the “Holders”), by the end of the

conversion period, the Company had

determined that there would be outstanding on the Conversion

Date

less than 1 million Series B Shares. Therefore, in accordance

with certain rights, privileges, restrictions

and conditions attaching to the Series A Shares and the

Series B Shares, the Company advised the

Holders that no Series A Shares would be converted into

Series B Shares and all remaining Series B

Shares would automatically be converted into Series A

Shares on a one-for-one basis on the Conversion

Date. On the Conversion Date, there were 6 million Series

A Shares and no Series B Shares outstanding.

On January 16, 2025, Emera announced that the annual fixed

dividend per share for Series F shares

would be reset from $1.0505 to $1.4372 for the five-year

period from and including February 15, 2025.

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 $34 million in 2026 (2025 – $38

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 $53 million for 2026 (2025 –

$51 million).

Defined Benefit Pension Plan Summary

in millions of dollars

Plans by region

TECO Holdings

NSPI

Caribbean

Total

Assets as at December 31, 2025

1,025

1,637

2,675

Accounting obligation at December 31, 2025

926

1,349

2,294

Accounting expense (income) during fiscal 2025

(13)

(4)

(7)

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,

2025 totalled $200 million (2024 – $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, 2025:

Emera, on behalf of Brunswick Pipeline, issued a standby

letter of credit for $22 million to secure

obligations under a non-revolving loan agreement. This

standby letter of credit has a one-year term,

expiring on March 31, 2026, and will be renewed annually,

as required.

TECO Holdings Inc. (“TECO Holdings”), issued a guarantee

in connection with SeaCoast’s performance

of obligations under a gas transportation precedent agreement.

The guarantee is for a maximum potential

amount of $45 million USD if SeaCoast fails to pay or perform

under the contract. The guarantee expires

five years after the gas transportation precedent agreement

termination date, which was terminated on

January 1, 2022. 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 issued a guarantee in connection with

SeaCoast’s performance obligations under a firm

service agreement, which expires December 31, 2055,

subject to two extension terms at the option of the

counterparty with a final expiration date of December 31, 2071.

The guarantee is for a maximum potential

amount of $13 million USD if SeaCoast fails to pay or perform

under the firm service agreement. 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 $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 $94 million USD (2024 – $104 million USD) with terms

of varying lengths.

Brunswick Pipeline, jointly and severally with Emera, have an

indemnity agreement in support of a $40

million surety bond issued in Brunswick Pipeline’s

favour to the CER. The purpose of the surety bond

is to

satisfy Brunswick Pipeline’s regulatory obligation

to have funds set aside for the future abandonment of

the pipeline.

The Company has standby letters of credit and surety

bonds in the amount of $271 million USD

(December 31, 2024 – $105 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 2026. The amount committed

as at December 31, 2025 was $70 million (December 31, 2024

– $58 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 25,

2025, the Board approved an increase in the annual common

share dividend rate to $2.9300 from

$2.9000 per common share. The first quarterly dividend payment

at the increased rate was paid on

November 15, 2025.

Emera’s common share dividends paid in 2025 were

$2.9075 ($0.7250 in Q1, Q2, and Q3 and $0.7325 in

Q4) per common share and for 2024 were $2.8775 ($0.7175

in Q1, Q2, and Q3 and $0.7250 in Q4) per

common share. This represents a dividend payout ratio of net

income of 86 per cent in 2025 (2024 – 168

per cent) and a dividend payout ratio of adjusted net income

of 83 per cent in 2025 (2024 – 98 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” on the Consolidated Statements of Income,

totalling $185 million for the year

ended December 31, 2025 (2024 – $324 million recovery).

NSPML is accounted for as an equity

investment, and therefore corresponding earnings related

to this revenue are reflected in “Income

from equity investments” on the Consolidated Statements of Income

For further details, refer to the

“Contractual Obligations” section.

●

Natural gas transportation capacity purchases from M&NP,

reported in “Operating revenue – non-

regulated” on the Consolidated Statements of Income,

totalled $16 million for the year ended

December 31, 2025 (2024 – $11

million).

●

On March 5, 2025, NSPI sold development assets associated

with the Wasoqonatl transmission

line

project to WTI for consideration of $15 million. The development

assets were sold at cost with no gain

or loss recognized in the Consolidated Statements of Income.

As at December 31, 2025, Emera and its associated companies

had $32 million due to related parties

(December 31, 2024 – $24 million) recorded in “Other

Current Liabilities” on the Consolidated Balance

Sheets.

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

Safety and Risk Committee (“SRC”) to

assist the Board in carrying out its safety,

risk and sustainability oversight responsibilities. The

SRC’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, reputation, 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 utilities 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 rate-regulated

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’s rate-regulated utilities are unable

to recover a material amount of costs in a timely manner,

are

unable to earn a return on invested capital, are disallowed the

recovery of certain costs, are subject to

regulatory penalties, are not permitted to make certain

capital investments, or are 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 with the choice

to use natural gas while in other

jurisdictions policies have been adopted to prevent limitations

on the use of natural gas.

Emerging laws

and policies addressing data center development may impact

load growth and the need for additional

utility infrastructure.

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, 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 have mandated timelines

for the shutdown of coal-fired generating facilities, set

renewable energy generation targets, and

introduced carbon pricing, and emissions limits. Over time,

these could potentially lead to a 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 contaminants

are ubiquitous in products and the environment, they could

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 land acquisition strategy

for

projects such as solar generation, which 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 seasonal weather

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 in

the future. Refer to “Climate 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 rate regulated 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, and increased

insurance costs, impacting cash flows and resulting in

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, lack of precipitation, and accumulation of fallen

dead vegetation also increase the risk of

wildfires resulting from the Company’s infrastructure

or for which the Company may otherwise have

responsibility. If 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, these 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 Risk

Physical Risk:

Changes in climate 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”).

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 related to the environment, renewable

energy, and

decarbonization continues to

shift in various operating jurisdictions, the Company is exposed

to increased uncertainty and risk arising

from policy, legal,

regulatory,

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 vary widely in operating jurisdictions

(refer to “Environmental Legislation”). The

Company’s ability to address transition risk for the

long-term is impacted by this increased policy

uncertainty and the need to balance stakeholder expectations

for reliability and affordability of energy.

The Company will be required to manage the impacts of these

ongoing changes on customer demand

and rates, while maintaining and integrating intermittent

renewable energy and new technologies, making

investments required to meet new resiliency and security standards,

and adapting the Company’s

infrastructure and generating capacity to meet load growth,

changing customer demands, and usage

patterns. The energy transition and the ability of the Company to

achieve government mandated

environmental requirements, will require significant capital

investment, and is dependent upon many

factors which are outside of the Company’s direct control,

including the actions of governments,

regulators, independent system operators, independent power producers,

interconnected utilities,

Indigenous communities, and other stakeholders;

the development and commercialization of new and

emerging technologies;

and the use of offsets. These external factors

and legislative, policy,

or regulatory

changes may cause the pace of the energy transition (including

emissions reductions and the addition of

more renewable energy) to materially differ from some

stakeholder expectations. 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

limited their exposure to coal-fired electricity generation

and are evaluating the medium and long-term

impacts of changes in climate which may result in less insurance

capacity, more

restrictive coverage and

increased premiums in the future. 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 risks associated

with changes in climate 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 increasingly relies on IT

systems, networks and cloud infrastructure, and third-party

service providers 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 (“AI”) 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 and back office 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. To

the extent that Emera maintains cybersecurity insurance coverage,

such coverage is subject to aggregate limits that, depending on

the scope and scale of impacts to the

Company, are more

likely to be exhausted as a result of a sophisticated single

cyberattack or if multiple

events were to occur within a single policy period. There is

no guarantee that the Company will be able to

renew such coverage on acceptable terms in the future.

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, by following program maturity objectives, through

periodic security assessments, by

exercising and improving cybersecurity incident readiness

and response programs, by hiring third-party

cybersecurity experts, and through 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 SRC on a

quarterly basis. The Board also oversees cybersecurity

risk, which is included in a risk dashboard at each

regularly scheduled Board meeting. The recruitment and retention

of qualified cybersecurity talent is a

global issue, and difficulties in securing such

resources may adversely impact the Company’s ability

address these risks.

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 utilities 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 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 Adverse Effect 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

impacts related to changes in climate, 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, which could result in 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 rate-regulated utilities, 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.

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.

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 trade restrictions, 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, the imposition

of custom duties or other tariffs, or an

increase in trade restrictions in the future could have

a Material Adverse Effect.

Fuel Supply Disruptions:

Emera’s electric and natural gas utilities are exposed

to the risk of fuel supply chain disruptions, both

within and outside their service territories. Fuel supply disruptions

may be caused by damage to,

operational issues with, terrorist or cyberattacks on, impacts

of severe weather or natural disasters on,

third party fuel production, storage, pipeline, and distribution

facilities. A significant unanticipated fuel

supply disruption could result in increased exposure to

commodity price risk for Emera’s regulated electric

and gas utilities and Emera Energy,

disruption to utility operations, and adverse reputational

impacts, any

of which 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.

Technology Risk

Emera relies on various technology systems to manage

operations, including increasing reliance on

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

operations, 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. Technological

reliance may increase vulnerability to cyberattacks

and data breaches

and increase operational reliance on technology systems

and third parties. The rapid evolution of AI has

the potential to disrupt existing business models and markets

and could result in a Material Adverse

Effect. If the Company does not successfully

integrate AI in a timely and cost-effective

manner, it may not

fully realize anticipated efficiencies, cost savings,

or service improvements.

If AI systems or tools do not

operate as expected, it could result in adverse operational, safety,

reputational, financial, legal, privacy,

data security, or other

outcomes. Emera’s digital transformation strategy,

including investment in

infrastructure modernization, emerging technologies such

as Generative AI, and customer focused

technologies, is driving increased investment in technology

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 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, cause

damage to Company infrastructure or third-party property,

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 uses financial instruments as a method

to manage its exposure to normal operating and

market risks relating to commodity prices, interest rates,

FX on forecast USD earnings and cash flows

and forecast future cash settlements of deferred compensation

obligations. In addition, the Company has

contracts for the physical purchase and sale of commodities. 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 proven to effectively hedge identified risk both at the inception and over the term of the instrument.

under this exemption if the criteria are no longer met.

Derivatives qualify for hedge accounting if they meet stringent

documentation requirements and can be

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. Any

gains or losses resulting from settlement of

these derivatives related to fuel for generation and purchased

power or cost of natural gas are expected

to 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

2025

2024

Regulatory Deferral:

Derivative instrument assets

(1)

Derivative instrument liabilities

(2)

(34)

(40)

Regulatory assets

(1)

Regulatory liabilities

(2)

(25)

(44)

Net asset

HFT Derivatives:

Derivative instrument assets

(1)

158

122

Derivatives instruments liabilities

(2)

(614)

(542)

Net liability

(456)

(420)

Other Derivatives:

Derivative instrument assets

(1)

Derivatives instruments liabilities

(2)

(1)

(36)

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

2025

2024

Regulatory Deferral:

Regulated fuel for generation and purchased power

(1)

(14)

(44)

HFT Derivatives:

Non-regulated operating revenues

467

207

Other Derivatives:

OM&G

Other income, net

(56)

Net gains (losses)

(42)

Total

net gains

517

121

(1) Realized gains (losses) on derivative instruments

settled and consumed in the period, hedging relationships

that have been

terminated or the hedged transaction is no longer

probable. Realized gains (losses) recorded in

inventory will be recognized in

“Regulated fuel for generation and purchased power”

when the hedged item is consumed.

As of December 31, 2025, the unrealized gain in AOCI

was $10 million, after-tax (December 31, 2024 –

$12 million, after-tax). For the year ended December 31,

2025, unrealized gains of $2 million (December

31, 2024 – $2 million) were reclassified into interest expense.

DISCLOSURE AND INTERNAL CONTROLS

Management is responsible for establishing and maintaining

adequate disclosure controls and

procedures (“DC&P”) and internal control over financial reporting

(“ICFR”), as defined in National

Instrument 52-109 Certification of Disclosure in Issuers’ Annual

and Interim Filings (“NI 52-109”). The

Company’s internal control framework is based

on 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, 2025 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.

Change in ICFR

In April 2025, the Company experienced a Cybersecurity

Incident that impacted certain financial systems

and processes at its Canadian affiliates. As a result,

the Company transitioned these to business

continuity processes and implemented additional ICFR during

this period. This transition to business

continuity processes resulted in a material change in the

Company’s ICFR at Canadian affiliates

during

the quarter ended June 30, 2025. Since this time, the

Company has restored certain financial systems

and transitioned back from corresponding business continuity

processes, which resulted in a material

change in the Company’s ICFR at its Canadian

affiliates during the second half of 2025. For

information on the Cybersecurity Incident, refer to the “Other

Developments” section.

There were no other changes in the Company’s ICFR,

during the year ended December 31, 2025, 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, 2025, the Company had recorded

$3,198 million (2024 – $3,427 million) of regulatory

assets and $1,669 million (2024 – $1,880 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 represents

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, 2025,

the balance of the accumulated reserve – COR

within regulatory liabilities was $729 million (2024 – $733

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,

over expected average remaining lifetime of inactive

members, depending on the makeup of Plan

memberships.

For the largest plans this is currently 16.4 years (8.0 years

for 2025 benefit cost) for

Canadian plans and a weighted average of 11.5

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:

2025

2024

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

5.66%

7.05%

5.27%

7.05%

TECO Holdings Group Supplemental

Executive Retirement Plan

(1)

5.41%

N/A

5.15%

N/A

TECO Holdings Group Benefit

Restoration Plan (1)

5.55%

N/A

5.18%

N/A

TECO Holdings Post-retirement Health

and Welfare Plan

5.69%

N/A

5.28%

N/A

NMGC Retiree Medical Plan

5.67%

4.25%

5.28%

4.25%

NSPI

4.63%, 4.72%

6.00%

4.63%, 4.62%

6.00%

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 $51 million in 2025 (2024 – $56 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 2025 benefit cost of $0.5

million and $2.0 million,

respectively (2024 – $0.5 million and $3.0 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, 2025,

unbilled revenues totalled $400 million (2024 – $342 million)

on total regulated operating revenues of

$8,571 million (2024 – $7,447 million).

PP&E

PP&E represents 61 per cent of total assets on the Company’s

consolidated 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 $1,259 million for the year

ended December 31, 2025 (2024 – $1,135 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, 2025, Emera’s goodwill represents

the excess of the acquisition purchase price for

the TEC and PGS 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 at that time and the

Company recorded a goodwill impairment charge of $210

million ($198 million, after-tax) or $155 million

USD ($146 million USD, after-tax) in Q3 2024. The reduced

NMGC goodwill balance of $289 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 2025, a qualitative assessment was performed for

PGS and TEC, given the significant excess of

FV over carrying amounts calculated during the last quantitative

tests in Q4 2024 and Q4 2023,

respectively. Management

concluded it was more likely than not that the FV of these

reporting units

exceeded their carrying amounts, including goodwill. As

such, no quantitative testing was required.

As of December 31, 2025, the Company had goodwill

with a total carrying amount of $5,580 million (2024

– $5,858 million). The change in the carrying value of goodwill from

2024 to 2025 was a result of 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 2025, impairment charges of $75 million ($71 million

after-tax) were recognized related to the NMGC

disposal group classified as held for sale and were recorded

in “Impairment charges” on the Consolidated

Income Statement. 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 Statements

of Income.

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, 2025, AROs recorded on the balance

sheet were $228 million (2024 – $217 million).

The Company estimates the undiscounted amount of cash

flow required to settle the obligations is

approximately $474 million (2024 – $453 million), which will

be incurred between 2026 and 2061. The

majority of these costs will be incurred between 2035

and 2051.

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 2025, is

described as follows:

Improvements to Income Tax

Disclosures

The Company adopted Accounting Standard Update (“ASU”) 2023-09,

Income Taxes

(Topic

740),

Improvements to Income Tax

Disclosures, effective December 31, 2025. 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. Adoption of the standard

resulted in additional disclosures provided in note 11

and note 31 of Emera’s consolidated financial

statements.

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.

Accounting for Government Grants Received by Business

Entities

In December 2025, the FASB

issued ASU 2025-10, Government Grants (Topic

832) – Accounting for

Government Grants Received by Business Entities. The

ASU adds guidance to ASC 832 on the

recognition, measurement, and presentation of government

grants. The guidance will be effective for

annual reporting periods beginning after December 15,

2028, and interim reporting periods within those

annual reporting periods. Early adoption is permitted. The standard

updates are to be applied using either

a modified prospective, modified retrospective, or full retrospective

approach, as detailed in the ASU. The

Company is currently evaluating the impact of adoption

of the standard update on its consolidated

financial statements.

Targeted Improvements

to the Accounting for Internal-Use Software

In September 2025, the FASB

issued ASU 2025-06, Intangibles – Goodwill and Other

– Internal-Use

Software (Subtopic 350-40): Targeted

Improvements to the Accounting for Internal-Use

Software. The

standard update modernizes accounting for internal-use

software by eliminating references to project

stages and clarifying the threshold to begin capitalizing

costs. The standard update also specifies that the

disclosure requirements under ASC 360, Property,

Plant and Equipment

apply to

capitalized software

costs accounted under ASC 350-40. The guidance will

be effective for annual reporting periods beginning

after December 15, 2027, and interim reporting periods

within those annual reporting periods. Early

adoption is permitted. The standard updates are to be applied

using either a prospective, retrospective, or

modified transition approach. The Company is currently

evaluating the impact of adoption of the standard

update on its 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.

SUMMARY OF QUARTERLY

RESULTS

For the quarter ended

millions of dollars

(except per share amounts)

2025

2024

Operating revenues

2,006

2,106

1,988

2,676

1,763

1,802

1,617

2,018

Net income attributable to common

shareholders

228

135

583

154

129

207

EPS – basic

0.23

0.76

0.45

1.96

0.52

0.01

0.45

0.73

EPS – diluted

0.25

0.76

0.45

1.96

0.52

0.01

0.45

0.73

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 2025 compared to Q4 2024

For explanation of variances, refer to the “Consolidated Income

Statement Highlights” section.

Q3 2025 compared to Q3 2024

For Q3 2025, net income attributable to common shareholders,

compared to Q3 2024, increased $224

million primarily due to charges related to the pending sale of

NMGC recognized in Q3 2024; and

increased earnings at TEC. These were partially offset

by increased MTM losses; lower earnings at NSPI

and NMGC; and higher Corporate costs. The change in EPS

was also impacted by an increase in

weighted average shares outstanding.

Q2 2025 compared to Q2 2024

Q2 2025 net income attributable to common shareholders

increased by $6 million primarily due to

decreased MTM losses; increased earnings at TEC, EES, and

NMGC; higher Corporate income tax

recovery; and decreased Corporate OM&G. These were

partially offset by the gain on sale of LIL

recognized in Q2 2024; charges related to the pending

sale of NMGC recognized in Q2 2025; lower

earnings at NSPI; decreased equity earnings from LIL;

and increased Corporate interest expense. Q2

2025 EPS – basic and diluted were consistent with Q2

2024.

Q1 2025 compared to Q1 2024

Q1 2025 net income attributable to common shareholders

increased by $376 million and EPS – basic and

diluted increased by $1.23 compared to Q1 2024. The increases

were primarily due to decreased MTM

losses; increased earnings at TEC, NSPI, EES and NMGC;

the impact of a weaker CAD; and decreased

Corporate OM&G. These changes were partially offset

by decreased income from equity investments due

to the sale of LIL. The change in EPS was also impacted

by an increase in weighted average shares

outstanding.

Exhibit 99.3

EMERA INCORPORATED

Consolidated

Financial Statements

December 31,

2025

and 2024

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 the standards of the Public Company

Accounting Oversight Board. Ernst & Young

LLP

has full and free access to the Audit Committee.

February 23, 2026

“Scott Balfour”

“Jared Green”

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, 2025 and 2024, 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, 2025 and 2024, and the consolidated results

of its operations and its consolidated cash

flows for each of the two years in the period ended December

31, 2025, 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 $3.2

billion in regulatory assets and $1.7 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 $289 million

and liabilities of $745 million,

disclosed in note 16 to the consolidated financial statements,

are measured at FV.

The

Company recognized $467 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 23, 2026

Emera Incorporated

Consolidated Statements of Income

For the

Year ended December 31

millions of dollars (except per share amounts)

2025

2024

Operating revenues

Regulated electric

6,858

5,872

Regulated gas

1,713

1,575

Non-regulated

205

(247)

Total

operating revenues (note 6)

8,776

7,200

Operating expenses

Regulated fuel for generation and purchased power

2,161

1,992

Regulated cost of natural gas

448

396

Operating, maintenance and general expenses ("OM&G")

2,337

1,918

Provincial, state, and municipal taxes

486

427

Depreciation and amortization

1,294

1,162

Impairment charges (note 4)

225

Total

operating expenses

6,801

6,120

Income from operations

1,975

1,080

Income from equity investments (note 8)

Other income, net (note 9)

165

203

Interest expense, net (note 10)

1,032

973

Income before provision for income taxes

1,171

409

Income tax expense (recovery) (note 11)

(159)

Net income

1,090

568

Non-controlling interest in subsidiaries ("NCI")

Preferred stock dividends

Net income attributable to common shareholders

1,014

494

Weighted average shares of common stock outstanding (in millions) (note 13)

Basic

299

289

Diluted

300

289

Earnings per common share (note 13)

Basic

3.39

1.71

Diluted

3.38

1.71

Dividends per common share declared Consolidated Statements of Comprehensive Income

2.9075

2.8775

The accompanying notes are an integral part of these consolidated financial statements.

Emera Incorporated

For the

Year ended December 31

millions of dollars

2025

2024

Net income

1,090

568

Other comprehensive income (loss) ("OCI"), net of tax

Foreign currency translation adjustment

(1)

(623)

1,027

Unrealized gains (losses) 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)

153

OCI

(4)

(388)

956

Comprehensive income

702

1,524

Comprehensive income attributable to NCI

Comprehensive Income of Emera Incorporated

701

1,523

The accompanying notes are an integral part of these consolidated financial statements.

1) Net of tax recovery of $

million for the year ended December 31, 2025

(2024 – $

million expense).

2) The Company has designated $

1.2

billion United States dollar (USD) denominated

Hybrid Notes as a hedge of the foreign

currency exposure of its net investment in USD

denominated operations.

3) Net of tax expense of $

million for the year ended December 31,

2025 (2024 –

nil

4) Net of tax recovery of $

million for the year ended December 31, 2025

(2024 – $

million expense).

Emera Incorporated

Consolidated Balance Sheets

As at

December 31

millions of dollars

2025

2024

Assets

Current assets

Cash and cash equivalents

349

196

Restricted cash

Inventory (note 15)

821

781

Derivative instruments (notes 16 and 17)

156

115

Regulatory assets (note 7)

409

595

Receivables and other current assets (note 19)

2,439

1,811

Assets held for sale (note 4)

199

173

4,389

3,688

Property, plant and equipment ("PP&E"),

net of accumulated depreciation

and amortization of $

10,845

and $

10,442

, respectively (note 21)

27,408

26,168

Other assets

Deferred income taxes (note 11)

421

392

Derivative instruments (notes 16 and 17)

Regulatory assets (note 7)

2,789

2,832

Net investment in direct finance and sales type leases (note 20)

572

610

Investments subject to significant influence (note 8)

634

654

Goodwill (note 23)

5,580

5,858

Other long-term assets (note 33)

894

538

Assets held for sale (note 4)

2,088

2,160

13,020

13,095

Total assets

44,817

42,951

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

2025

2024

Liabilities and Equity

Current liabilities

Short-term debt (note 24)

1,807

1,400

Current portion of long-term debt (note 26)

1,201

234

Accounts payable

1,948

1,992

Derivative instruments (notes 16 and 17)

534

526

Regulatory liabilities (note 7)

211

262

Other current liabilities (note 25)

535

489

Liabilities associated with assets held for sale (note 4)

391

212

6,627

5,115

Long-term liabilities

Long-term debt (note 26)

18,453

18,173

Deferred income taxes (note 11)

2,516

2,331

Derivative instruments (notes 16 and 17)

115

Regulatory liabilities (note 7)

1,458

1,618

Pension and post-retirement liabilities (note 22)

268

274

Other long-term liabilities (note 8 and 27)

960

910

Liabilities associated with assets held for sale (note 4)

1,024

1,148

24,794

24,545

Equity

Common stock (note 12)

9,387

9,042

Cumulative preferred stock (note 29)

1,422

Contributed surplus

Accumulated other comprehensive income ("AOCI') (note 14)

873

1,261

Retained earnings

1,614

1,468

Total

Emera Incorporated equity

13,382

13,277

NCI (note 30)

Total

equity

13,396

13,291

Total liabilities and equity

44,817

42,951

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 Consolidated Statements of Cash Flows

Emera Incorporated

For the

Year ended December 31

millions of dollars

2025

2024

Operating activities

Net income

1,090

568

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization

1,298

1,165

Income from equity investments, net of dividends

(8)

Allowance for funds used during construction ("AFUDC") – equity

(62)

(53)

Deferred income taxes, net

(191)

Net change in pension and post-retirement liabilities

(40)

(46)

Nova Scotia Power ("NSPI") fuel adjustment mechanism ("FAM")

(158)

451

Net change in fair value ("FV") of derivative instruments

228

Net change in regulatory assets and liabilities

296

(226)

Net change in capitalized transportation capacity

(65)

175

Impairment charges

214

Gain on sale of the Labrador Island Link Partnership (“LIL”), excluding transaction costs

(4)

(191)

Other operating activities, net

108

Changes in non-cash working capital (note 31)

(757)

452

Net cash provided by operating activities

1,802

2,646

Investing activities

Additions to PP&E

(3,532)

(3,151)

Proceeds on disposal of assets

Proceeds from disposal of investment subject to significant influence

927

Other investing activities

(1)

Net cash used in investing activities

(3,482)

(2,218)

Financing activities

Change in short-term debt, net

(78)

Proceeds from short-term debt with maturities greater than 90 days

598

Proceeds from long-term debt, net of issuance costs

2,016

1,361

Retirement of long-term debt

(201)

(1,086)

Net proceeds (repayments) under committed credit facilities

119

(825)

Issuance of common stock, net of issuance costs

284

Dividends on common stock

(576)

(538)

Dividends on preferred stock

(75)

(73)

Other financing activities

(9)

Net cash provided by (used in) financing activities

1,841

(818)

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

associated with assets held for sale

(11)

Net increase (decrease) in cash, cash equivalents, restricted cash and cash

associated with assets held for sale

150

(367)

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

beginning of year

221

588

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

end of year

371

221

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

sale consists of:

Cash

344

191

Short-term investments

Restricted cash

Cash associated with assets held for sale

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

371

221

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, 2024

9,042

1,422

1,261

1,468

13,291

Net income of Emera Inc.

1,089

1,090

Other comprehensive loss, net of

tax recovery of $

million

(388)

Dividends declared on preferred

stock (note 29)

(75)

Dividends declared on common

stock ($

2.9075

/share)

(868)

Issued under the at-the-market

program ("ATM"), net of after-tax

issuance costs

Issued under the Dividend

Reinvestment Program ("DRIP"),

net of discount

293

Senior management stock

options exercised and Employee

Common Share Purchase Plan

("ECSPP")

Other

(1)

Balance, December 31, 2025

9,387

1,422

873

1,614

13,396

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 ATM, net of

after-tax issuance costs

261

Issued under the DRIP,

net of

discount

291

Senior management stock options

exercised and ECSPP

Other

(1)

Balance, December 31, 2024

9,042

1,422

1,261

1,468

13,291

The accompanying notes are an integral part of these consolidated financial statements.

Emera Incorporated

Notes to the Consolidated Financial Statements

As at December 31, 2025 and 2024

1. 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, 2025, Emera’s reportable segments

include the following:

●

Florida Electric Utility,

which consists of Tampa

Electric (“TEC”), a vertically integrated regulated

electric utility, serving

approximately

866,000

customers in West Central Florida.

●

Canadian Electric Utilities, which includes:

●

NSPI, a vertically integrated regulated electric utility and

the primary electricity supplier in Nova

Scotia, serving approximately

565,000

customers;

●

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; and

●

per cent indirect voting equity interest in Wasoqonatl

Transmission Incorporated (“WTI”),

transmission line project to create a reliability intertie between

Nova Scotia and New Brunswick.

For more information, refer to note 8.

●

Gas Utilities and Infrastructure, which includes:

●

Peoples Gas System Inc. (“PGS”), a regulated gas distribution

utility, serving

approximately

523,000

customers across Florida;

●

New Mexico Gas Company,

Inc. (“NMGC”), a regulated gas distribution utility,

serving

approximately

553,000

customers in New Mexico. On August 5, 2024,

Emera announced an

agreement to sell NMGC. The transaction is expected to

close in the first half of 2026, subject to

certain approvals, including approval by the New Mexico

Public Regulation Commission

(“NMPRC”). For more information on the pending transaction,

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

137,000

customers;

●

Grand Bahama Power Company Limited (“GBPC”), a vertically

integrated regulated electric utility

on Grand Bahama Island, serving approximately

20,000

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”),

660

MW pumped storage hydroelectric facility in northwestern

Massachusetts.

●

Emera US Finance LP (“Emera Finance”), EUSHI Finance, Inc.

(“EUSHI Finance”) and TECO

Finance, Inc. (“TECO Finance”), financing subsidiaries

of Emera;

●

Emera US Holdings Inc. (“EUSHI”), 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 details, 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, 2025, Emera’s goodwill represent

ed the excess of the acquisition purchase price for

the TEC and PGS 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 at that time and the

Company recorded a goodwill impairment charge of $

210

million ($

198

million, after-tax) or $

155

million

USD ($

146

million USD, after-tax) in Q3 2024. The reduced NMGC

goodwill balance of $

289

million is

included in the NMGC disposal unit classified as held for

sale. For further details, refer to note 23.

In Q4 2025, qualitative assessments were performed for

PGS and TEC given the significant excess of FV

over carrying amounts calculated during the last quantitative

tests in Q4 2024 and Q4 2023, respectively.

Management concluded it was more likely than not that

the FV of these reporting units exceeded their

carrying amounts, including goodwill. As such, no quantitative

testing was required.

Income Taxes and

Investment and Production 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

and production 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 details, refer to note 11.

Derivatives and Hedging Activities

The Company uses financial instruments as a method

to manage its exposure to normal operating and

market risks relating to commodity prices, interest rates,

FX on forecast USD earnings and cash flows

and forecast future cash settlements of deferred compensation

obligations. In addition, the Company has

contracts for the physical purchase and sale of commodities. 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

under this exemption if the criteria are no longer met.

Derivatives qualify for hedge accounting if they meet stringent

documentation requirements and can be

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. Any

gains or losses resulting from settlement of

these derivatives related to fuel for generation and purchased

power or cost of natural gas are expected

to 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” on

the Consolidated Balance Sheets 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”

on the Consolidated Balance Sheets.

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.

Lease liabilities and right-of-use assets are recognized

on the Consolidated Balance Sheets based on the

present value of the future minimum lease payments over

the lease term at commencement date. As

most of Emera’s leases do not provide an implicit rate,

the incremental borrowing rate at commencement

of the lease is used in determining the present value of

future lease payments. For operating leases,

expense is recognized on a straight-line basis over the

lease term and is recorded as “OM&G” on the

Consolidated Statements of Income. For finance leases,

the amortization of the ROU asset is recorded as

"Depreciation and amortization expense" and the interest

on lease liabilities is recorded as "Interest

expense, net" on the Consolidated Statements of Income.

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.

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 In 2025, impairment charges of $

valuation and pricing activities.

million ($

million after-tax) were recognized related to the NMGC

disposal group classified as held for sale and were recorded

in “Impairment charges” on the Consolidated

Statements of Income. 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 Statements of Income.

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 2025 or 2024.

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

2025 or 2024.

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 The Company has several stock-based compensation plans: a common share option plan for senior

estimated future cash outlays.

Stock-Based Compensation

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 details, 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 2025, the Company received an aggregate of $

million (2024 – $

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 2025 and 2024 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,

2027. For the year-end December 31, 2025, NSPI received

million (2024 – $

million) in funding

under the grant, which has been recorded as a reduction to

the carrying amount of the project in

PP&E

Cybersecurity Incident

On April 25, 2025, Emera and NSPI discovered a cybersecurity

incident (the “Cybersecurity Incident”)

involving unauthorized access into certain parts of its Canadian

IT network and servers supporting

portions of its business applications. There was no disruption

to the Canadian physical operations or to

Emera’s US or Caribbean utilities’ operations.

The Company implemented business continuity processes

for certain impacted business and

administrative functions at its Canadian affiliates. The

systematic restoration of affected IT systems and

corresponding transition away from business continuity processes

continues to progress in a planned,

controlled and phased approach. The Company maintains cyber

insurance coverage and is working with

its insurer on the claims process.

2. CHANGE IN ACCOUNTING POLICY

The new USGAAP accounting policy that is applicable

to, and adopted by the Company in 2025, is

described as follows:

Improvements to Income Tax

Disclosures

The Company adopted Accounting Standard Update (“ASU”) 2023-09,

Income Taxes

(Topic

740),

Improvements to Income Tax

Disclosures, effective December 31, 2025. 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. Adoption of the standard

resulted in additional disclosures provided in note 11

and note 31.

3. 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.

Accounting for Government Grants Received by Business

Entities

In December 2025, the FASB

issued ASU 2025-10, Government Grants (Topic

832) – Accounting for

Government Grants Received by Business Entities. The

ASU adds guidance to ASC 832 on the

recognition, measurement, and presentation of government

grants. The guidance will be effective for

annual reporting periods beginning after December 15,

2028, and interim reporting periods within those

annual reporting periods. Early adoption is permitted. The standard

updates are to be applied using either

a modified prospective, modified retrospective, or full retrospective

approach, as detailed in the ASU. The

Company is currently evaluating the impact of adoption

of the standard update on its consolidated

financial statements.

Targeted Improvements

to the Accounting for Internal-Use Software

In September 2025, the FASB

issued ASU 2025-06, Intangibles – Goodwill and Other

– Internal-Use

Software (Subtopic 350-40): Targeted

Improvements to the Accounting for Internal-Use

Software. The

standard update modernizes accounting for internal-use

software by eliminating references to project

stages and clarifying the threshold to begin capitalizing

costs. The standard update also specifies that the

disclosure requirements under ASC 360, Property,

Plant and Equipment

apply to

capitalized software

costs accounted under ASC 350-40. The guidance will

be effective for annual reporting periods beginning

after December 15, 2027, and interim reporting periods

within those annual reporting periods. Early

adoption is permitted. The standard updates are to be applied

using either a prospective, retrospective, or

modified transition approach. The Company is currently

evaluating the impact of adoption of the standard

update on its 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.

4. 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.

As a result of the pending sale,

NMGC’s assets and

liabilities were classified as held for sale in Q3 2024 and

the carrying value of the assets and liabilities

were adjusted to FV less cost to sell.

As the transaction proceeds will be lower than the carrying amount

of the assets and liabilities being sold,

in Q3 2024 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.

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.

At each reporting date, the Company performs an assessment of

the FV of the disposal group by

comparing the FV of expected transaction proceeds, less

costs to sell, to the carrying value of net assets,

including goodwill ("carrying amount"). On June 30, 2025,

the Company remeasured the NMGC disposal

group at the lower of its carrying amount and FV less costs

to sell. As a result of the change in the

expected timing of the transaction close, a non-cash impairment

charge of $

million ($

million, after-

tax), or $

million USD ($

million USD, after-tax), was recorded in “Impairment

charges” on the

Consolidated Statements of Income in Q2 2025. An additional

loss for estimated future transaction costs

of $

million ($

million after-tax) was recorded in “Other income, net” on

the Consolidated Statements of

Income in Q2 2025. There were no additional adjustments recorded

in 2025.

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, 2025. Of the $

million ($

million USD) recorded to date, $ Details of the assets and liabilities classified as held for sale are as follows:

million ($

million USD)

was recorded in 2025.

As at

December 31

millions of dollars

2025

2024

Cash and cash equivalents

Inventory

Derivative instruments

Regulatory assets

Receivables and other current assets

142

127

Current assets held for sale

199

173

PP&E

1,856

1,845

Regulatory assets

Goodwill

289

303

Other long-term assets

Less: Adjustment to FV less costs to sell

(1)

(89)

(17)

Long-term assets held for sale

2,088

2,160

Total assets held for sale

2,287

2,333

Short-term debt

116

Current portion of long-term debt

Derivative instruments

Regulatory liabilities

Accounts payable and other current liabilities

154

155

Current liabilities associated with assets held for sale

391

212

Long-term debt

567

696

Deferred income taxes

185

167

Regulatory liabilities

261

274

Other long-term liabilities

Long-term liabilities associated with assets held for sale

1,024

1,148

Total liabilities associated with assets held for sale

1,415

1,360

(1) Represents a $

million impairment charge related to the remeasurement

of the NMGC disposal group to FV (December

31,

2024 -

nil

) and $

million in estimated transaction costs related to

the pending sale (December 31, 2024 – $

million).

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, 2025, the estimated FV of the escrow proceeds

receivable was $

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 an incremental $

million tax benefit related to loss

carryforwards applied against the taxable capital gain on the sale.

5. SEGMENT INFORMATION

Emera manages its reportable

segments

separately due in part to their different operating,

regulatory and

geographical environments. Segments are reported based

on each subsidiary’s contribution of revenues,

net income attributable to common shareholders and total

assets, as reported to the Company’s chief

operating decision maker (“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, 2025

Operating revenues from

external customers (1)

4,336

1,944

1,737

577

182

8,776

Inter-segment revenues

(1)

(53)

Total operating revenues

4,346

1,944

1,756

577

206

(53)

8,776

Regulated fuel for generation

and purchased power

982

904

294

(19)

2,161

Regulated cost of natural gas

448

OM&G

1,135

457

491

145

140

(31)

2,337

Provincial, state and municipal

taxes

318

114

486

Depreciation and amortization

705

298

207

1,294

Impairment charges

Income (loss) from equity

investments

(1)

Other income, net

165

Interest expense, net

(2)

305

172

149

385

1,032

Income tax expense

(recovery)

140

(45)

(115)

NCI in subsidiaries

Preferred stock dividends

Net income (loss) attributable

to common shareholders

845

182

276

(332)

1,014

Capital expenditures

2,153

630

619

3,502

As at December 31, 2025

Total assets

24,636

8,546

8,476

1,439

2,469

(749)

44,817

Investments subject to

significant influence

471

108

634

Goodwill

4,796

784

5,580

(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, 2025, 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, 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 charge

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.

Geographical Information

Revenues: (based on country of origin of the product or service sold)

For the

Year ended December 31

millions of dollars

2025

2024

United States

6,185

4,712

Canada

2,014

1,922

Barbados

415

427

The Bahamas

162

139

8,776

7,200

PP&E:

As at

December 31

millions of dollars

2025

2024

United States

(1)

20,931

20,084

Canada

5,476

5,068

Barbados

640

645

The Bahamas

361

371

27,408

26,168

(1) On August 5, 2024, Emera announced an agreement to sell

NMGC. As a result, NMGC's assets and liabilities were

classified as held for sale and

excluded from the table above beginning in Q3 2024. For further

details on the pending transaction, refer to note 4.

6. 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, 2025

Regulated Revenue

Residential

2,489

1,073

201

770

4,533

Commercial

1,147

522

308

528

2,505

Industrial

272

270

102

(19)

653

Other electric

457

507

Regulatory deferrals

(41)

(20)

Other (1)

269

(10)

329

Finance income (2)(3)

Regulated revenue

4,346

1,944

577

1,733

(29)

8,571

Non-Regulated Revenue

Marketing and trading margin (4)

158

Other non-regulated operating

revenue

(25)

Mark-to-market (3)

Non-regulated revenue

206

(24)

205

Total operating revenues

4,346

1,944

577

1,756

206

(53)

8,776

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

(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, and long-term steam

supply arrangements with fixed contract terms. As of December

31, 2025, the aggregate amount of the

transaction price allocated to remaining performance

obligations was $

344

million (2024 – $

495

million),

including $

million related to NMGC. This amount includes $

121

million of future performance

obligations related to a gas transportation contract between

SeaCoast and PGS through

2040

, and $

million of future performance obligations related to asset

management agreements between PGS and

EES through 2030. 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 Regulatory assets represent prudently incurred costs that have been deferred because it is probable they

obligations through

2040

7. REGULATORY

ASSETS AND LIABILITIES

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

2025 (1)

2024 (1)

Regulatory assets

Deferred income tax regulatory assets

1,385

1,227

TEC capital cost recovery for early retired assets

727

737

Pension and post-retirement medical plan

316

395

Storm cost recovery clauses

206

613

TEC capital cost recovery for retired Polk Unit 1 components

178

205

NSPI FAM

102

Cost recovery clauses

Deferrals related to derivative instruments

Environmental remediations

Stranded cost recovery

Other

(2)

141

119

3,198

3,427

Current

409

595

Long-term

2,789

2,832

Total

regulatory assets

3,198

3,427

Regulatory liabilities

Deferred income tax regulatory liabilities

751

828

Accumulated reserve – COR

729

733

Cost recovery clauses

121

BLPC Self-insurance fund ("SIF") (note 33)

Deferrals related to derivative instruments

NSPI FAM

Other

(2)

1,669

1,880

Current

211

262

Long-term

1,458

1,618

Total

regulatory liabilities

1,669

1,880

(1) On August 5, 2024, Emera announced

an agreement to sell NMGC. As a result,

NMGC's assets and liabilities were classified

as held for

sale beginning in Q3 2024 and excluded

from the table above. For further details

on the pending transaction, refer to note

(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 being

recovered as a separate line item on customer bills for

a period of

years, beginning in January 2022.

Pension and Post-Retirement Medical Plan

This asset is primarily related to the deferred costs of pension and

post-retirement benefits at TEC and

PGS. 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, as

applicable and amortized over the

remaining service life of plan participants.

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 NSEB approved storm rider for each of 2023,

2024 and 2025, which gives NSPI the option to

apply to the NSEB for recovery of costs if major storm

restoration expense exceeds approximately $

million in a given year. 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. The Hurricane Matthew asset

was fully amortized at the end of 2024.

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 are being recovered through base rates over an

-year recovery period beginning on January 1,

2025.

NSPI FAM

NSPI has a NSEB approved FAM,

allowing NSPI to recover fluctuating fuel and certain fuel-related

costs

from customers through annual fuel rate adjustments.

Differences between prudently incurred fuel costs

and amounts recovered from customers through electricity

rates in a given year are deferred to a FAM

regulatory asset or liability and recovered from or returned

to customers in subsequent periods.

Cost Recovery Clauses

These assets and liabilities are clauses and riders related to

TEC and PGS. They are recovered or

refunded through cost-recovery mechanisms approved

by the FPSC as applicable, on a dollar-for-dollar

basis in a subsequent period.

Deferrals Related to Derivative Instruments

This asset is primarily related to NSPI deferring changes in FV

of derivatives that are documented as

economic hedges or that do not qualify for NPNS exemption,

as a regulatory asset or liability as approved

by the NSEB. 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.

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.

Accumulated Reserve – COR

This regulatory asset or liability represents the non-ARO

COR reserve in TEC, PGS and NSPI. AROs

represent the FV of estimated cash flows associated with

the Company’s legal obligation to retire its

PP&E. Non-ARO COR represent estimated funds received

from customers through depreciation rates to

cover future COR of PP&E value upon retirement that

are not legally required. This reduces rate base for

ratemaking purposes. This liability is reduced as COR are incurred

and increased as depreciation is

recorded for existing assets and as new assets are put

into service.

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 2025 was

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

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

clauses.

Base Rates:

On December 3, 2024, the

FPSC rendered a decision which included 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 rate case

decision, effective January 1, 2025. In

February 2025, a motion for reconsideration on certain

aspects of the final order was filed by an

intervening party with the FPSC. On May 6, 2025, the

FPSC denied the motion for reconsideration,

except with respect to immaterial calculation corrections,

and the final order was issued on June 11,

2025. In March 2025, two intervening parties each filed a notice

of appeal to the Florida Supreme Court

regarding the outcome of TEC’s 2024 base rate

proceeding. On January 12, 2026, the intervening parties

filed their briefs related to the appeal. To

date, the FPSC has not responded to the briefs.

On September 4, 2025, TEC petitioned the FPSC to

increase base revenue by $

million USD to reflect

the 2026 adjustment in accordance with its 2024 rate case

decision. On November 4, 2025, the FPSC

approved the adjustment, with new rates effective

January 1, 2026.

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.

Storm Reserve:

On February 4, 2025, the FPSC approved TEC’s

petition 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

-month recovery period beginning March

2025. The amount of cost-recovery is subject to a true-up

mechanism with the FPSC.

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 by the NSEB. The Public Utilities

Act gives the NSEB supervisory powers over

NSPI’s operations and expenditures. Electricity

rates for NSPI’s customers are also subject

to NSEB

approval. 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 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 NSEB’s

request.

NSPI’s approved regulated ROE range for 2025 and

2024 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 On September 18, 2025, NSPI filed a consensus General Rate Application (“GRA”) with the NSEB,

base.

General Rate Application (“GRA”):

reflecting a settlement agreement reached with customer

representatives. The GRA proposes average

annual rate increases of

1.8

per cent in 2026 and

2.4

per cent in 2027. The proposed rates would result

annual revenue (fuel and non-fuel) increases of $

million in 2026 and $

108

million in 2027. The hearing

for the matter concluded in January 2026.

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

November 29, 2024, the NSEB approved NSPML’s

application to issue the debt, transfer the proceeds

NSPI as a refund of a portion of previous NSPML assessment

payments, and 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.

FAM Asset Sale:

On April 17, 2024, the NSEB 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.

Storm Rider:

On December 2, 2024, the NSEB 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:

NSPI has NSEB approved regulatory assets for the deferred

recognition of $

million in incremental

operating costs incurred during the Hurricane Fiona storm

restoration efforts, and $

million of

undepreciated costs related to assets retired, because

of Hurricane Fiona in September 2022. Beginning

on July 1, 2024, these regulatory assets are being amortized

over a

-year period.

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 December 23, 2025, NSPML received an interim order

from the NSEB to collect up to $

199

million

from NSPI for the recovery of costs associated with the

Maritime Link in 2026, subject to a monthly

holdback of up to $

million.

On February 4, 2026, NSPML submitted an application with

the NSEB requesting the termination of the

holdback mechanism.

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

NSEB to collect up to $

197

million in 2025

from NSPI, which included $

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 were subject to a holdback of up

to $

million per month. There was

holdback

recorded for the year ended December 31, 2025 (2024 –

nil

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. Base rates are determined in FPSC rate setting

hearings which can occur at the

initiative of PGS, the FPSC or other interested parties.

PGS’s approved ROE range for 2025 and 2024

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 March 31, 2025, PGS filed a rate case with the FPSC for

new rates to become effective January 1,

2026. On August 13, 2025, PGS and the intervening parties

filed a settlement agreement with the FPSC

for a $

million USD increase in 2026 annual base rates, which includes

million USD from the cast

iron and bare steel replacement rider,

and additional adjustments of $

million USD in 2027 and up to $

million USD in 2028, subject to FPSC approval. This reflects

10.30

per cent midpoint ROE and

54.7

per

cent equity thickness. On October 31, 2025, the FPSC

issued the final order approving the settlement.

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 or revenue requirements equal to

its cost of providing service, plus an appropriate

return on invested capital.

NMGC’s approved ROE for 2025 and 2024

was

9.375

per cent on an allowed equity capital structure of On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates.

per cent.

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 2025 and 2024.

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 was

heard in December 2025 and will continue in early 2026.

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 November 2025, the Government of Barbados

and BLPC agreed to new Transmission,

Distribution, Sales and Dispatch (“T&D”) and Generation

and

Energy Storage (“G&S”) licenses. The G&S license will be

valid until 2047, unless otherwise extended.

The T&D license will be valid for

30 years

. These new non-exclusive licenses have since been

signed

and will become effective upon the repeal of

the existing license. BLPC continues to operate

under its

current statutory authority while preparing for the transition

to the new licensing framework.

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.

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

8.52

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.

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 2025 and 2024,

the fuel pass

through charge was adjusted monthly,

in-line with actual fuel and other associated costs.

8. 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

2025

2024

2025

2024

2025

NSPML

462

475

100.0

M&NP

(1)

108

124

12.9

Lucelec

(1)

19.5

WTI

(2)

50.0

Bear Swamp

(3)

(1)

50.0

LIL

(4)

634

654

(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 March 5, 2025, NSPI, the Canada

Infrastructure Bank ("CIB") and the Wskijinu'k Mtmo'taquow

Agency ("WMA") announced

the Wasoqonatl transmission line project to create a reliable intertie

between Nova Scotia and New Brunswick. The project

owned by a new regulated utility, WTI, which is wholly-owned by a newly

formed limited partnership between NSPI, CIB and

WMA.

NSPI is responsible for providing construction, operation,

maintenance and administrative services to

WTI. NSPI's ownership

interest is based on a

per cent indirect voting interest in WTI.

As of December 31, 2025, NSPI's economic

interest based on the

million invested is

per cent.

(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 (2024 – $

million) is recorded in Other long-term liabilities

on the

Consolidated Balance Sheets.

(4) On June 4, 2024, Emera completed the sale

of its equity interest in the LIL. For further

details, refer to note 4.

Equity investment in Lucelec includes 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

2025

2024

Balance Sheets

Current assets

PP&E

1,380

1,425

Regulatory assets

782

778

Non-current assets

Total

assets

2,229

2,267

Current liabilities

Long-term debt

(1)

1,495

1,570

Non-current liabilities

185

167

Equity

462

475

Total

liabilities and equity

2,229

2,267

(1) The project debt has been guaranteed

by the Government of Canada.

9. OTHER INCOME, NET

For the

Year ended December 31

millions of dollars

2025

2024

AFUDC

Interest income

Pension non-current service cost recovery

FX gains (losses)

(58)

Gain on sale of LIL, net of transaction costs

(1)

182

Transaction costs related to the pending sale of NMGC

(1)

(2)

(25)

Charges related to wind-down costs and certain asset impairments

(2)

(29)

Other

165

203

(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.

10. INTEREST EXPENSE, NET

For the

Year ended December 31

millions of dollars

2025

2024

Interest on debt

1,048

1,004

Allowance for borrowed funds used during construction

(30)

(23)

Other

(8)

1,032

973

11. INCOME TAXES

The income tax provision, for the years ended December

31, differs from that computed using the

enacted Canadian federal statutory income tax rate for the following

reasons:

millions of dollars

2025

2024

Income before provision for income taxes

1,171

409

Income taxes, at statutory income tax rate

176

Domestic reconciling items:

Investment tax credits

(36)

(3)

Deferred income taxes on regulated income recorded as

regulatory assets and regulatory liabilities

(18)

(2)

(44)

(11)

Valuation allowance

(14)

(1)

(30)

(7)

Net Part VI.1 tax

Interest and financing expenses

(30)

(7)

Additional impact from the sale of LIL equity interest

Other

(8)

(1)

(3)

(1)

Provincial income taxes

(1)

(31)

(3)

(130)

(32)

Foreign reconciling items:

United States

Federal tax rate variance

Production tax credits

(51)

(4)

(41)

(10)

State income tax, net of federal income tax benefit

Amortization of deferred income tax regulatory liabilities

(45)

(4)

(37)

(9)

Investment tax credits

(39)

(3)

(8)

(2)

Deferral and amortization of Investment tax credits

(4)

(1)

Impairment charges

Other

(3)

(8)

(2)

Other foreign jurisdictions

(5)

(7)

(2)

Income tax expense (recovery)

(159)

(39)

(1) The majority of provincial income taxes relate

to Nova Scotia.

US One Big Beautiful Bill Act (“OBBBA”):

On July 4, 2025, the OBBBA was signed into law.

The OBBBA makes permanent many of the expired

and expiring tax provisions originally enacted in the Tax

Cuts and Jobs Act of 2017. It also includes

significant changes in future years to the timing and availability

of several clean energy tax credits

previously enacted in the Inflation Reduction Act, including

the investment tax credit and production tax

credit. On August 15, 2025, the Internal Revenue Service

released guidance on determining when wind

and solar projects have begun construction for purposes

of qualifying for these tax credits. Emera’s 2025

financial statements were not materially impacted as a

result of the enacted changes.

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 current and future interest

and financing expenses were expected to be

denied under the EIFEL legislation and, as a result, the

financing structure was wound up. It was

determined that Emera was more likely than not to realize

the benefit of the current denied interest and

financing expenses and therefore a $

million deferred income tax asset and related income tax

benefit

was recorded during Q4 2024. In addition, Emera recognized

a $

million income tax benefit related to

the reversal of a deferred income tax liability on the wind-up of

the financing structure. During 2024, the

total tax benefit of $

million was recorded in “Income tax expense (recovery)”

on the Consolidated

Statements of Income and included in the Other segment.

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

2025

2024

Canada

157

(175)

United States

961

534

Other

Income before provision for income taxes

1,171

409

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:

Canada

United

millions of dollars

(Federal)

(Provincial)

States

Other

Total

2025

Current income taxes

(6)

Deferred income taxes – exclusive of the

components listed below

208

257

Benefits of operating loss carryforwards

(41)

(39)

(2)

(84)

Net tax credits

(72)

Adjustments to beginning of the year valuation

allowance

(14)

(13)

(3)

(30)

Income tax expense (recovery)

(38)

(31)

147

2024

Current income taxes

Deferred income taxes – exclusive of the

components listed below

(104)

(98)

208

Benefits of operating loss carryforwards

(2)

(76)

(80)

Adjustments to beginning of the year valuation

allowance

(31)

(30)

(61)

Net tax credits

(57)

Income tax (recovery) expense

(108)

(130)

(159)

The deferred income tax assets and liabilities presented in

the Consolidated Balance Sheets as at

December 31 consisted of the following:

millions of dollars

2025

2024

Deferred income tax assets:

Tax

loss carryforwards

1,028

1,118

Tax

credit carryforwards

596

534

Regulatory liabilities

295

321

Pension and other post-retirement liabilities

173

197

Derivative instruments

143

144

Other

463

432

Total

deferred income tax assets before valuation allowance

2,698

2,746

Valuation allowance

(317)

(322)

Total

deferred income tax assets after valuation allowance

2,381

2,424

Deferred income tax liabilities:

PP&E

(3,462)

(3,307)

Regulatory assets

(358)

(420)

Pension and other post-retirement assets

(335)

(286)

Other

(321)

(350)

Total

deferred income tax liabilities

(4,476)

(4,363)

Consolidated Balance Sheets presentation:

Long-term deferred income tax assets

421

392

Long-term deferred income tax liabilities

(2,516)

(2,331)

Net deferred income tax liabilities Considering all evidence regarding the utilization of the Company’s deferred income tax assets, it has

(2,095)

(1,939)

been determined that Emera is more likely than not to realize

all recorded deferred income tax assets,

except for certain loss carryforwards, denied interest and

financing expenses and unrealized capital

losses on long-term debt and investments. A valuation

allowance of $

317

million has been recorded as at

December 31, 2025 (2024 – $

322

million) related to the loss carryforwards, denied interest

and financing

expenses, long-term debt and investments. During 2025,

the Company recognized a $

million (2024 -

million) net tax benefit primarily due to the utilization

of certain loss carryforwards, which were subject

to a valuation allowance at the beginning of the year.

The Company intends to indefinitely reinvest earnings

from certain foreign operations. It is impractical to

estimate the amount of income and withholding tax that might

be payable if such earnings were

repatriated.

Emera’s net operating loss ("NOL"), capital loss

and tax credit carryforwards and their expiration periods

as at December 31, 2025 consisted of the following:

Subject to

Tax

Valuation

Net Tax

Expiration

millions of dollars

Carryforwards

Allowance

Carryforwards

Period

Canada

NOL

2,649

(876)

1,773

2026 - 2045

Capital loss

(55)

Indefinite

Tax credit

(2)

2028 - 2044

United States

Federal NOL

909

(1)

908

2037 - Indefinite

State NOL

937

(30)

907

2026 - Indefinite

Capital loss

2029

Tax credit

595

(1)

594

2026 - 2045

Other

NOL

108

(20)

2026 - 2031

The following table provides details of the change in unrecognized

tax benefits for the years ended

December 31 as follows:

millions of dollars

2025

2024

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)

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, 2025 was $

million (2024 – $

million), which would decrease the effective

tax rate if recognized.

The total amount of accrued interest with respect to unrecognized

tax benefits was $

million (2024 –

million) with $

million interest expense recognized in the Consolidated

Statements of Income (2024

– $

million).

penalties have been accrued.

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 (2024 – $

126

million), including interest. NSPI has prepaid $

million

(2024 – $

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,

2025, the Company’s tax years still open to examination

by taxing authorities include 2006 and

subsequent years.

12. COMMON STOCK

Authorized

: Unlimited number of non-par value common shares.

2025

2024

Issued and outstanding:

millions of

dollars

millions of

dollars

Balance, December 31, 2024

295.94

9,042

284.12

8,462

Conversion of Convertible Debentures

0.02

Issuance of common stock under ATM program

(1)(2)

0.19

5.12

261

Issued under the DRIP,

net of discounts

4.83

293

6.10

291

Senior management stock options exercised and Employee Share

Purchase Plan

0.78

0.60

Balance, December 31, 2025

301.76

9,387

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).

(2) For the year ended December 31, 2025, a

total of

187,600

common shares were issued under Emera's ATM program at an

average price of $

53.58

per share for gross proceeds of $

million ($

million net of after-tax issuance costs). As at December

31,

2025, an aggregate gross sales limit of $

600

million remained available for issuance under

the ATM program.

As at December 31, 2025, the following common shares

were reserved for issuance:

million (2024 –

million) under the senior management stock option plan,

million (2024 –

million) under the employee

common share purchase plan and

million (2024 –

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, 2025,

Emera was in compliance with this requirement.

ATM Equity Program

On December 5, 2025, Emera renewed its ATM

Program by filing a prospectus supplement to the

Company's Canadian short form base shelf prospectus

with the securities regulatory authorities in each of

the provinces of Canada. At the same time, Emera filed a US

prospectus supplement to the Company’s

US base prospectus included in its US registration statement

on Form F-10 with the US Securities and

Exchange Commission (the “SEC”). The ATM

Program 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 is expected to remain in effect until

January 5, 2029.

13. 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)

2025

2024

Numerator

Net income attributable to common shareholders

1,014.2

493.6

Diluted numerator

1,014.2

493.6

Denominator

Weighted average shares of common stock outstanding – basic

299.2

289.1

Stock-based compensation

0.5

0.1

Weighted average shares of common stock outstanding – diluted

299.7

289.2

Earnings per common share

Basic

3.39

1.71

Diluted

3.38

1.71

14. 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, 2025

Balance, January 1, 2025

1,396

(163)

1,261

OCI before

reclassifications

(623)

(539)

Amounts reclassified from

AOCI

(2)

153

151

Net current period OCI

(623)

(2)

153

(388)

Balance, December 31, 2025

773

(81)

169

873

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

The reclassifications out of AOCI are as follows:

For the

Year ended December 31

millions of dollars

2025

2024

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 (gains) losses

Other income, net

(2)

Past service costs (gains)

Other income, net

(2)

Amounts reclassified into obligations

Pension and post-retirement benefits

156

Total

before tax

156

Income tax expense

(3)

Total

net of tax

153

Total reclassifications out of AOCI, net of tax, for the period

151

15. INVENTORY

As at

December 31

millions of dollars

2025

2024

Materials

484

453

Fuel

337

328

Total

821

781

16. 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

2025

2024

2025

2024

Regulatory deferral:

Commodity swaps and forwards

FX forwards

HFT derivatives:

Power swaps and physical contracts

Natural gas swaps, futures, forwards, physical

contracts

238

236

695

660

289

270

745

690

Other derivatives:

Equity derivatives

FX forwards

Total

gross derivatives

330

322

781

773

Impact of master netting agreements:

Regulatory deferral

(1)

(7)

(1)

(7)

HFT derivatives

(131)

(148)

(131)

(148)

Total

impact of master netting agreements

(132)

(155)

(132)

(155)

Less: Derivatives classified as held for sale

(1)

Total derivatives

198

166

649

617

Current

(2)

156

115

534

526

Long-term

(2)

115

Total derivatives

198

166

649

617

(1) On August 5, 2024, Emera announced an

agreement to sell NMGC. As a result,

NMGC's assets and liabilities were classified as

held for sale beginning in Q3 2024.

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,

2025, the

unrealized gain in AOCI was $

million, after-tax (December 31, 2024 – $

million, after-tax). For the

year ended December 31, 2025, unrealized gains of $

million (2024 - $

million) were 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

swaps and

millions of dollars

forwards

For the year ended December 31

2025

2024

Unrealized (loss) gain in regulatory assets

(36)

(27)

Unrealized gain (loss) in regulatory liabilities

(12)

Realized gain in regulatory assets

(7)

(8)

Realized loss in regulatory liabilities

Realized loss (gain) in inventory

(1)

(8)

Realized loss (gain) in regulated fuel for generation and

purchased power

(2)

(4)

(6)

Total

change in derivative instruments

(23)

(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, 2025, the Company had the following

notional volumes designated for regulatory

deferral that are expected to settle as outlined below:

millions

2026

2027-2028

Commodity swaps and forwards purchases:

Natural gas (MMBtu)

Power (MWh)

FX forwards:

FX contracts (millions of USD)

175

Weighted average rate

1.3569

1.3534

% of USD requirements

64%

16%

HFT Derivatives

The Company has recognized the following realized and

unrealized gains with respect to HFT derivatives:

For the

Year ended December 31

millions of dollars

2025

2024

Power swaps and physical contracts in non-regulated operating revenues

Natural gas swaps, forwards, futures and physical contracts in non-regulated As at December 31, 2025, the Company had the following notional volumes of outstanding HFT

operating revenues

463

195

Total

gains in net income

467

207

derivatives that are expected to settle as outlined below:

2030 and

millions

2026

2027

2028

2029

thereafter

Natural gas purchases (Mmbtu)

473

140

Natural gas sales (Mmbtu)

492

Power purchases (MWh)

Power sales (MWh)

Other Derivatives

As at December 31, 2025, 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

3.2

million shares and extends until December of 2026.

The FX forwards have a

combined notional amount of $

300

million USD and expire in 2026 through 2028.

For the

Year ended December 31

millions of dollars

2025

2024

Equity

Forwards

Derivatives

Forwards

Derivatives

Unrealized gain (loss) in OM&G

(2)

Unrealized gain (loss) in other income, net

(44)

Realized gain in OM&G

Realized loss in other income, net

(16)

(12)

Total

gains (losses) in net income

(56)

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, 2025, the maximum exposure the

Company had to credit risk was $

billion (2024 –

1.3

billion), which included accounts receivable net of collateral/deposits and assets related to It is possible that volatility in commodity prices could cause the Company to have material credit risk

derivatives.

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, 2025 was

301

million (2024 – $

303

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, 2025, the Company had $

207

million (2024 – $

140

million) in financial assets,

considered to be past due, which have been outstanding for

an average 77 days. The FV of these

financial assets was $

192

million (2024 – $

128

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, 2025

December 31, 2024

millions of

dollars

% of total

exposure

millions of

dollars

% of total

exposure

Receivables, net

Regulated utilities:

Residential

471

20%

376

22%

Commercial

211

184

11%

Industrial

Other

177

105

Cash collateral

956

41%

784

46%

Trading group:

Credit rating of A- or above

146

Credit rating of BBB- to BBB+

Not rated

416

18%

165

10%

640

27%

295

17%

Other accounts receivable

408

17%

331

20%

Classification as assets held for sale

(1)

134

118

2,138

92%

1,528

90%

Derivative Instruments

(current and long-term)

Credit rating of A- or above

Credit rating of BBB- to BBB+

Not rated

198

166

10%

2,336

100%

1,694

100%

(1) On August 5, 2024, Emera announced an

agreement to sell NMGC. As a result,

NMGC's assets and liabilities were classified as

held for sale beginning in Q3 2024.

For further details on the pending transaction, refer

to note 4.

Cash Collateral

The Company’s cash collateral positions consisted

of the following:

As at

December 31

millions of dollars

2025

2024

Cash collateral provided to others

193

198

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, 2025, the total FV of derivatives

in a liability position was $

649

million (December 31,

2024

–

617

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.

17. 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, 2025

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

(1)

Natural gas swaps, futures, forwards, physical

contracts and related transportation

123

117

158

Other derivatives:

FX forwards

Equity derivatives

Total assets

128

198

Liabilities

Regulatory deferral:

Commodity swaps and forwards

FX forwards

HFT derivatives:

Power swaps and physical contracts

(4)

Natural gas swaps, futures, forwards and physical

contracts

115

464

580

(3)

146

471

614

Other derivatives:

FX forwards

Total liabilities

170

471

649

Net assets (liabilities)

(42)

(430)

(451)

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 a result,

NMGC's assets and liabilities were classified as

held for sale beginning in Q3 2024. For further details

on the pending transaction, refer to note 4.

The change in the FV of the Level 3 financial assets and liabilities

for the year ended December 31, 2025

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

Balance, December 31, 2025

Liabilities

Balance, beginning of period

437

441

Total

realized and unrealized gains (losses) included in non-regulated operating

revenues

Balance, December 31, 2025

464

471

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 The Company uses a modelled pricing valuation technique for determining the FV of Level 3 derivative

peers.

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, 2025

HFT derivatives – Power

Third-party pricing

$27.35

$150.55

$88.79

swaps and physical contracts

HFT derivatives – Natural

464

Third-party pricing

$0.51

$18.45

$11.85

gas swaps, futures, forwards

and physical contracts

Total

471

Net liability

430

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

(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, 2025

19,654

18,956

18,535

421

18,956

December 31, 2024

18,407

17,941

17,688

253

17,941

The Company has designated $

1.2

billion USD denominated Hybrid Notes as a hedge of the

foreign

currency exposure of its net

investment in USD denominated operations. The Company’s

Hybrid Notes

are contingently convertible into preferred shares in the

event of bankruptcy or other related events. A

redemption option on or after June 15, 2026 is available

and at the control of the Company.

The Hybrid

Notes are classified as Level 2 financial assets. As at

December 31, 2025, the FV of the Hybrid Notes

was $

1.2

billion USD (2024 – $

1.2

billion USD). An after-tax foreign currency gain of $

million was

recorded in AOCI for the year ended December 31, 2025 (2024 – $ In the ordinary course of business, Emera provides energy and other services and enters into

139

million after-tax loss).

18. RELATED PARTY

TRANSACTIONS

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

185

million for the year ended December 31, 2025 (2024

– $

324

million

recovery). 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,

reported in “Operating revenue – non-

regulated” on the Consolidated Statements of Income,

totalled $

million for the year ended

December 31, 2025 (2024 – $

million).

●

On March 5, 2025, NSPI sold development assets associated

with the Wasoqonatl transmission

line

project to WTI for consideration of $

million. The development assets were sold at cost

with no gain

or loss recognized in the Consolidated Statements of Income.

As at December 31, 2025, Emera and its associated companies

had $

million due to related parties

(December 31, 2024 – $

million) recorded in “Other Current Liabilities” on the Consolidated

Balance

Sheets.

19. RECEIVABLES AND OTHER CURRENT ASSETS

As at

December 31

millions of dollars

2025

2024

Customer accounts receivable – billed

1,265

834

Customer accounts receivable – unbilled

400

342

Capitalized transportation capacity

(1)

238

216

Cash collateral provided to others

193

198

Prepaid expenses

105

Sales tax receivable

Income tax receivable

Allowance for credit losses

(15)

(12)

Other

150

Total

receivables and other current assets

2,439

1,811

(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.

20. LEASES

Lessee

The Company has operating leases for buildings, land, telecommunication services, and rail cars and

finance leases for land and buildings. Emera’s leases have remaining lease terms of 2 years 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

2025

2024

Operating leases:

Right-of-use asset

Other long-term assets

Operating lease liabilities

Current

Other current liabilities

Long-term

Other long-term liabilities

Total

operating lease liabilities

Finance leases:

Right-of-use asset

PP&E

Finance lease liabilities

Current

Other current liabilities

Long-term

Other long-term liabilities

Total

finance lease liabilities

The amounts recognized in the Consolidated Statements of Income

consisted of the following:

For the

Year ended December

millions of dollars

Classification

2025

2024

Operating leases:

Operating Lease expense

OM&G

Finance leases:

Variable costs for power generation finance

leases

Regulated fuel for generation

and purchased power

115

112

Amortization of right-of-use asset

Depreciation and

amortization

Interest on finance lease liability

Interest expense, net

Total

finance lease liabilities

122

112

Future minimum lease payments under non-cancellable

leases for each of the next five years and in

aggregate thereafter are as follows:

millions of dollars

2026

2027

2028

2029

2030

Thereafter

Total

Operating leases:

Minimum lease payments

109

124

Less imputed interest

(70)

Total

future minimum lease payments for operating leases

Finance Leases:

Minimum lease payments

161

181

Less imputed interest

(112)

Total future minimum payments for finance leases Additional information related to Emera's leases is as follows:

For the

Year ended December 31

millions of dollars (except as indicated)

2025

2024

Operating

Leases

Finance

Leases

Operating

Leases

Finance

Leases

Cash paid for amounts included in the

measurement of lease liabilities:

Operating cash flows for leases

Right-of-use assets obtained in exchange for

lease obligations

Operating leases

Finance leases

Weighted average remaining lease term (years)

Weighted average discount rate

3.98%

5.54%

3.96%

5.20%

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.

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

2025

2024

Total

minimum lease payment to be received

1,180

1,310

Less: amounts representing estimated executory costs

(166)

(182)

Minimum lease payments receivable

1,014

1,128

Estimated residual value of leased property (unguaranteed)

183

Less: Credit loss reserve

(1)

(2)

Less: unearned finance lease income

(580)

(655)

Net investment in direct finance and sales-type leases

616

654

Principal due within one year (included in "Receivables and other

current assets")

Net Investment in direct finance and sales type leases – long-term As at December 31, 2025, future minimum lease payments to be received for each of the next five years

572

610

and in aggregate thereafter were as follows:

millions of dollars

2026

2027

2028

2029

2030

Thereafter

Total

Minimum lease payments to be

received

702

1,180

Less: executory costs

(166)

Total

1,014

21. 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

2025 (1)

2024(1)

Generation

131

14,673

14,297

Transmission

3,379

3,106

Distribution

9,359

8,512

Gas transmission and distribution

4,815

4,658

General plant and other

(2)

3,643

3,078

Total

cost

35,869

33,651

Less: Accumulated depreciation

(2)

(10,845)

(10,442)

25,024

23,209

Construction work in progress

(2)

2,384

2,959

Net book value

27,408

26,168

(1) On August 5, 2024, Emera announced an

agreement to sell NMGC. As a result,

NMGC's assets and liabilities were classified as

held for sale beginning in Q3 2024 and excluded

from the table above.

For further details on the pending transaction, refer

to note

(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, 2025, SeaCoast’s

share of plant in service was $

million USD (2024 – $

million USD), and

accumulated depreciation of $

million USD (2024 – $

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.

22. 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

2025

2024

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

2,367

241

2,273

227

Service cost

Plan participant contributions

Interest cost

114

110

Plan amendments

Benefits paid

(160)

(22)

(153)

(21)

Actuarial losses (gains)

(1)

(18)

(2)

(3)

FX translation adjustment

(49)

(10)

Balance, December 31

2,294

232

2,367

241

Change in plan assets:

Balance, January 1

2,493

2,298

Employer contributions

Plan participant contributions

Benefits paid

(160)

(22)

(153)

(21)

Actual return on assets, net of expenses

345

226

FX translation adjustment

(46)

(2)

Balance, December 31

2,675

2,493

Funded status, end of year

381

(177)

126

(187)

(1) The actuarial gains recognized in the period

are primarily due to higher than expected

investment returns and changes in

actuarial assumptions.

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

2025

2024

DB pension

plans

Non-pension

benefit plans

DB pension

plans

Non-pension

benefit plans

PBO/APBO

212

219

FV of plan assets

Funded status

(83)

(212)

(84)

(219)

Plans with Accumulated Benefit Obligation (“ABO”)

in Excess of Plan Assets

The ABO for the DB pension plans was $

2,114

million as at December 31, 2025 (2024 – $

2,255

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

2025

2024

DB pension

plans

DB pension

plans

ABO

FV of plan assets

Funded status

(79)

Balance Sheet

The amounts recognized in the Consolidated Balance Sheets

consisted of the following:

As at

December 31

millions of dollars

2025

2024

DB pension

plans

Non-pension

benefit plans

DB pension

plans

Non-pension

benefit plans

Other current liabilities

(5)

(17)

(5)

(21)

Liabilities associated with assets held for

sale

(1)

(4)

(1)

Long-term liabilities

(77)

(191)

(78)

(196)

Other long-term assets

473

208

Assets held for sale

(1)

(9)

AOCI, net of tax and regulatory assets

125

354

Deferred income tax expense in AOCI

(12)

(8)

(1)

Net amount recognized

494

(159)

472

(166)

(1) On August 5, 2024, Emera announced an

agreement to sell NMGC. As a result,

NMGC's assets and liabilities were classified as

held for sale beginning in Q3 2024. 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, 2025

363

(17)

Amortized in current period

(9)

Current year changes

(51)

(158)

Change in FX rate

(16)

Balance, December 31, 2025

287

(174)

Non-pension benefits plans:

Balance, January 1, 2025

(8)

Amortized in current period

(3)

Current year changes

(3)

Change in FX rate

(1)

Balance, December 31, 2025

(5)

(2)

As at

December 31

millions of dollars

2025

2024

DB pension

plans

Non-pension

benefit plans

DB pension

plans

Non-pension

benefit plans

Actuarial (gains) losses

(174)

(5)

(17)

(8)

Past service gains

(2)

Deferred income tax expense

AOCI, net of tax

(162)

(7)

(9)

(7)

Regulatory assets

287

363

Assets held for sale

(1)

AOCI, net of tax and regulatory assets

125

354

(1) On August 5, 2024, Emera announced

an agreement to sell NMGC. As a result,

NMGC's assets and liabilities were classified

as held for

sale beginning in Q3 2024. For further details

on the pending transaction, refer to note

Benefit Cost Components

Emera's net periodic benefit cost included the following:

As at

Year ended December 31

millions of dollars

2025

2024

DB pension

plans

Non-pension

benefit plans

DB pension

plans

Non-pension

benefit plans

Service cost

Interest cost

114

110

Expected return on plan assets

(164)

(2)

(160)

(2)

Current year amortization of:

Actuarial losses (gains)

(1)

(2)

Past service gains

(2)

Regulatory assets

(2)

Settlement, curtailments

Total

(7)

(3)

The expected return on plan assets is determined based on

the market-related value of plan assets of

2,686

million as at January 1, 2025 (2024 – $

2,571

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, 2025

Cash and cash equivalents

Net in-transits

(27)

(1)

Equity securities:

Canadian

117

United States

262

Other

146

Fixed income securities:

Government

110

Corporate

Other

Mutual funds

Open-ended investments

measured at NAV

(1)

1,335

Common collective trusts

measured at NAV

(2)

570

Total

1,905

579

191

2,675

100

As at

December 31, 2024

Cash and cash equivalents

Net in-transits

(27)

(1)

Equity securities:

Canadian

109

United States

312

Other

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

(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, 2025 and 2024, 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

2026

Expected benefit payments

2026

170

2027

174

2028

174

2029

176

2030

173

2031 – 2035

899

109

Assumptions

The following table shows the assumptions that have been

used in accounting for DB pension and other

post-retirement benefit plans:

2025

2024

(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

5.11

4.87

5.07

4.91

Discount rate - future service

5.21

5.08

5.12

5.00

Rate of compensation increase

3.73

3.82

3.73

3.72

Health care trend

- initial (next year)

6.73

6.53

- ultimate

3.77

- year ultimate reached

2045

2044

Benefit cost for year ended December 31

Discount rate - past service

5.07

4.91

4.89

Discount rate - future service

5.12

5.00

4.88

4.89

Expected long-term return on plan assets

6.42

3.65

6.43

3.69

Rate of compensation increase

3.73

3.72

3.87

3.85

Health care trend

- initial (current year)

6.53

6.04

- ultimate

3.77

3.76

- year ultimate reached

2044

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, 2025 was $ The change in goodwill for the year ended December 31 was due to the following:

million (2024 – $

million).

23. GOODWILL

millions of dollars

2025

2024

Balance, January 1

5,858

5,871

Change in FX rate

(278)

504

Impairment charges

(214)

Classified as assets held for sale

(1)

(303)

Balance, December 31

5,580

5,858

(1) On August 5, 2024, Emera announced an

agreement to sell NMGC. As a result,

NMGC's assets and liabilities were

classified as held for sale beginning in Q3 2024.

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, 2025, related to the TEC and PGS reporting

units.

In Q4 2025, qualitative assessments were performed for

PGS and TEC given the significant excess of FV

over carrying amounts calculated during the last quantitative

tests in Q4 2024 and Q4 2023, respectively.

Management concluded it was more likely than not that

the FV of these reporting units exceeded their

carrying amounts, including goodwill. As such, no quantitative

testing was required.

In Q3 2024, Emera announced an agreement to sell NMGC.

As a result, a quantitative goodwill

impairment assessment was performed on the NMGC

reporting unit at that time and the Company

recorded a goodwill impairment charge of $

210

million, pre-tax, in Q3 2024. The reduced NMGC goodwill

balance is included in the NMGC disposal unit classified as held

for sale. For further details, refer to note

24. 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

2025

Weighted

average

interest rate

2024

Weighted

average

interest rate

Florida Electric Utility

Advances on revolving credit facilities

1,059

4.01

915

4.77

Canadian Electric Utilities

Advances on non-revolving credit facilities

500

3.35

Bank indebtedness

Gas Utilities and Infrastructure

PGS – Advances on revolving credit facilities

199

4.63

199

5.36

NMGC – Advances on revolving credit facilities

4.77

5.52

NMGC – Advances on non-revolving term facilities

4.63

Other Electric Utilities

GBPC – Advances on revolving credit facilities

7.20

Other

TECO Finance – Advances on revolving credit and term facilities

5.21

265

5.53

Emera – Bank indebtedness

1,923

1,446

Adjustment

Classification as liabilities held for sale

(1)

(116)

(46)

Short-term debt

1,807

1,400

(1) On August 5, 2024, Emera announced

an agreement to sell NMGC. As a result,

NMGC's assets and liabilities were classified

as held for

sale beginning in Q3 2024. For further details

on the pending transaction, refer to note

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

2025

2024

TEC – committed revolving credit facility

2030

1,645

1,151

TECO Finance – committed revolving credit facility

2030

548

576

NSPI – non-revolving credit facility

2026

500

PGS – revolving credit facility

2030

343

360

NMGC – revolving credit facility

(1)

2027

171

180

NMGC – non-revolving term facility

(1)

2026

Other – committed revolving credit facilities

Various

Total

3,332

2,302

Less:

Advances under revolving credit and term facilities

1,881

1,400

Letters of credit issued within the credit facilities

Total

advances under available facilities

1,884

1,404

Available capacity under existing agreements

1,448

898

(1) On August 5, 2024, Emera announced an

agreement to sell NMGC. As a result,

NMGC's assets and liabilities were classified as

held for sale beginning in Q3 2024. For further details

on the pending transaction, refer to note 4.

The weighted average interest rate on outstanding short-term

debt at December 31, 2025 was

4.24

per

cent (2024 –

5.05

per cent).

Recent Significant Financing Activity by Segment

Florida Electric Utilities

On November 20, 2025, TEC amended and restated its

800

million USD committed revolving credit

facility to extend the maturity date from

December 1, 2028

, to

November 20, 2030

and increased the

amount to $

1.2

billion USD. There were no other material

changes in commercial terms from the prior

agreement.

Canadian Electric Utilities

On May 21, 2025, NSPI entered into a $

500

million non-revolving facility which matures on

May 21, 2026

The credit agreement contains customary representations

and warranties, events of default and financial

and other covenants. The non-revolving facility’s

interest rates are referenced to the Term

CORRA or

prime rate, plus a margin.

Gas Utilities and Infrastructure

On November 20, 2025, PGS amended and restated its

250

million USD unsecured committed revolving

credit facility to extend the maturity date from

December 1, 2028

, to

November 20, 2030

. There were no

other changes in commercial terms from the prior agreement.

On October 23, 2025, NMGC entered into a $

million USD,

364

-day term loan agreement which

matures on

October 22, 2026

. The credit agreement contains customary representations

and warranties,

events of default and financial and other covenants. The non-revolving

facility’s interest rates are

referenced to the Term

SOFR plus a margin.

On September 19, 2025, NMGC amended its $

125

million USD unsecured committed revolving credit

facility to extend the maturity date from

December 17, 2026

, to

December 17, 2027

. There were no other

changes in commercial terms from the prior agreement.

Other

On November 20, 2025, TECO Finance amended and

restated its $

400

million USD unsecured

committed revolving credit facility to extend the maturity

date from

December 1, 2028

, to

November 20,

2030

. There were no other changes in commercial terms

from the prior agreement.

25. OTHER CURRENT LIABILITIES

As at

December 31

millions of dollars

2025

2024

Accrued charges

229

189

Accrued interest on long-term debt

137

106

Pension and post-retirement liabilities (note 22)

Sales and other taxes payable

Income tax payable

Other

128

153

535

489

26. 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

2025

2024

Maturity

2025

2024

Florida Electric Utility

Senior unsecured notes

4.46%

4.36%

2029 - 2051

6,271

5,720

Canadian Electric Utilities

NSPI – Commercial paper

(2)

Variable

2029

559

177

NSPI – Senior unsecured notes

4.98%

5.12%

2026 - 2097

3,114

3,184

3,673

3,361

Gas Utilities and Infrastructure

PGS – Senior unsecured notes

5.63%

2028 - 2053

1,268

1,331

NMGC – Senior unsecured notes

3.78%

2026 - 2051

665

698

EBP – Secured loan notes

Variable

2028

219

250

2,152

2,279

Other Electric Utilities

Unsecured loan notes

4.08%

4.06%

2026 - 2032

142

143

Unsecured loan notes

Variable

2027 - 2028

113

104

Secured senior notes and debentures

(3)

2.19%

2.38%

2026 - 2040

171

169

426

416

Other

Unsecured loan notes

Variable

2026 - 2029

723

992

Senior unsecured notes

3.99%

2026 - 2046

3,358

3,525

Senior unsecured notes

4.84%

2030

500

Fixed to floating subordinated notes

(4)

6.75%

2076

1,645

1,727

Junior subordinated notes

6.80%

7.63%

2054 - 2056

1,713

720

7,939

7,464

Adjustments

Debt issuance costs

(144)

(137)

Classification as liabilities held for sale

(5)

(663)

(696)

Amount due within one year

(6)

(1,201)

(234)

(2,008)

(1,067)

Long-Term Debt

18,453

18,173

(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 2025, the Company recognized $

113

million in interest expense (2024 – $

110

million) related to its fixed to floating subordinated

notes.

(5) On August 5, 2024, Emera announced

an agreement to sell NMGC. Since Q3

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 and non-revolving

credit facilities, outstanding borrowings and

available capacity as at December 31 were as follows:

millions of dollars

Maturity

2025

2024

Emera – committed revolving credit facility

(1)

June 2029

1,300

NSPI – revolving credit facility

(1)

June 2029

800

Emera – Unsecured non-revolving credit facility

February 2027

200

Total

2,300

Less:

Borrowings under credit facilities

1,284

1,169

Letters of credit issued inside credit facilities

Use of available facilities

1,301

1,181

Available capacity under existing agreements

999

1,119

(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, 2025

Emera

Syndicated credit facilities

Debt to capital ratio

Less than or equal to

0.70

to 1

0.53

: 1

Recent Significant Financing Activity by Segment

Florida Electric Utility

On March 6, 2025, TEC issued $

600

million USD of senior unsecured notes that bear

interest at

5.15

per

cent with a maturity date of

March 1, 2035

Other

On February 20, 2026, Emera amended its $

200

million unsecured non-revolving facility to extend the

maturity date from

February 20, 2026

February 19, 2027

. There were no other material changes to the

terms from the prior agreement.

On September 25, 2025, EUSHI Finance, EUSHI, and Emera

filed a shelf registration statement on Form

F-10 and Form F-3 (“Registration Statement”), with the

Nova Scotia Securities Commission (“NSSC”) and

the US Securities and Exchange Commission (“SEC”)

under the US/Canada Multijurisdictional Disclosure

System. The Registration Statement was filed in connection

with the prospective offer and issue by

EUSHI Finance of one or more series of senior and/or

subordinated unsecured debt securities (“Debt

Securities”), in an aggregate principal amount of up to

billion USD, during the

-month period that the

short form base shelf prospectus contained in the Registration

Statement (“Base Shelf Prospectus”),

including any further amendments thereto, remains valid.

The Debt Securities may be offered in one or

more transactions, at prices, with maturities and on terms

to be set forth in one or more prospectus

supplements to be filed with the NSSC and the SEC at the time

of any such offering.

On October 3, 2025, EUSHI Finance completed an issuance

of $

750

million USD fixed-to-fixed reset rate

junior subordinated notes, pursuant to the prospectus

supplement dated September 29, 2025, to the

Base Shelf Prospectus. The notes initially bear interest

at a rate of

6.25

per cent, and will reset on

April 1,

2031

, and every

five years

thereafter, to a rate per annum

equal to the five-year US treasury rate plus

2.509

per cent, subject to an interest rate floor of

6.25

per cent. The notes mature on April 1, 2056.

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, plus accrued and unpaid interest on the notes

to be redeemed, in accordance with the

terms of the prospectus supplement; and otherwise, at

the times and the redemption prices described in

the prospectus supplement. The notes are fully and

unconditionally guaranteed, on a joint, several and

subordinated basis, by Emera, and EUSHI.

On February 20, 2025, Emera amended its $

200

million unsecured non-revolving facility to extend the

maturity date from

February 20, 2025

February 20, 2026

. There were no other material changes to the

terms from the prior agreement.

Long-Term Debt Maturities

As at December 31, 2025, 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

2026

2027

2028

2029

2030

Thereafter

Total

Florida Electric Utility

685

5,586

6,271

Canadian Electric Utilities

599

3,034

3,673

Gas Utilities and

Infrastructure

(1)

127

637

1,357

2,152

Other Electric Utilities

102

126

426

Other

1,028

200

522

500

5,689

7,939

Total

1,297

321

763

1,824

554

15,702

20,461

(1) Includes NMGC maturities classified as held

for sale.

27. 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

2025

2024

Balance, January 1

217

192

Accretion included in depreciation expense

Additions

Revisions in estimated cash flows

Classified as assets held for sale

(1)

Liabilities settled

(2)

Change in FX rate

(2)

Balance, December 31

228

217

(1) On August 5, 2024, Emera announced an

agreement to sell NMGC. As a result,

NMGC's assets and liabilities were classified as

held for sale beginning in Q3 2024. For further details

on the pending transaction, refer to note 4.

28. COMMITMENTS AND CONTINGENCIES

Commitments

As at December 31, 2025, 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

2026

2027

2028

2029

2030

Thereafter

Total

Purchased power

(1)

413

422

411

459

451

5,941

8,097

Transportation

(2) (3)

780

588

478

413

370

2,954

5,583

Fuel, gas supply and storage

(4)

674

239

159

156

1,325

Capital projects

288

395

Other

144

294

651

2,299

1,386

1,133

1,083

902

9,248

16,051

As detailed below, contractual obligations at December 31, 2025 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 (2026: $

million, 2027: $

million, 2028: $

million, 2029: $

million, 2030: $

million,

thereafter: $

million).

(3) Purchasing commitments for transportation of

fuel and transportation capacity on various pipelines.

Includes a commitment of

121

million related to a gas transportation contract between

PGS and SeaCoast through 2040.

(4) Includes $

101

million related to NMGC (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. On December

23, 2025, NSPML received an interim order from

the NSEB to collect up to $

199

million from NSPI for the recovery of costs associated with

the Maritime

Link in 2026, subject to a monthly holdback of up to $

million. The timing and amounts payable to

NSPML for the remainder of the

-year commitment period are subject to NSEB 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, 2025, 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, reputation, 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 Safety and Risk Committee (“SRC”) to

assist in carrying out its risk and sustainability

oversight responsibilities. The SRC’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 utilities 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 rate-regulated

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’s rate-regulated utilities are unable

to recover a material amount of costs in a timely manner,

are

unable to earn a return on invested capital, are disallowed

the recovery of certain costs, are subject to

regulatory penalties, are not permitted to make certain

capital investments, or are 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 utilities 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 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 Adverse Effect 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

impacts related to changes in climate, 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 The Company has exposure to the macro-economic conditions in North America and in other geographic

compensation.

General Economic Risk

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 which could result in 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 rate-regulated utilities, 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, 2025:

Emera, on behalf of Brunswick Pipeline, issued a standby

letter of credit for $

million to secure

obligations under a non-revolving loan agreement. This

standby letter of credit has a one-year term,

expiring on March 31, 2026, and will be renewed annually,

as required.

TECO Holdings Inc. (“TECO Holdings”), issued a guarantee

in connection with SeaCoast’s performance

of obligations under a gas transportation precedent agreement.

The guarantee is for a maximum potential

amount of $

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 issued a guarantee in connection with

SeaCoast’s performance obligations under a firm

service agreement, which expires December 31, 2055,

subject to two extension terms at the option of the

counterparty with a final expiration date of December 31, 2071.

The guarantee is for a maximum potential

amount of $

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.

Brunswick Pipeline, jointly and severally with Emera, have an

indemnity agreement in support of a $

million surety bond issued in Brunswick Pipeline’s

favour to the CER. The purpose of the surety bond

is to

satisfy Brunswick Pipeline’s regulatory obligation

to have funds set aside for the future abandonment of

the pipeline.

NSPI has guarantees on behalf of its subsidiary,

NS Power Energy Marketing Incorporated, in the amount

of $

million USD (2024 – $

104

million USD) with terms of varying lengths.

The Company has standby letters of credit and surety

bonds in the amount of $

271

million USD

(December 31, 2024 – $

105

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 2026. The amount committed

as at December 31, 2025 was $

million (December 31, 2024 – $

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, 2025 and 2024, 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 2025, NSPI recognized

million net expense (2024 – $

million) in “Regulated fuel for generation and purchased

power” and $

million (2024 – $

million) in

“OM&G” on the Consolidated Statements of Income.

29. CUMULATIVE PREFERRED STOCK

Authorized:

Unlimited number of First Preferred shares, issuable in

series.

Unlimited number of Second Preferred shares, issuable in

series.

December 31, 2025

December 31, 2024

Annual Dividend

Redemption

Issued and

Net

Issued and

Net

Per Share

Price per share

Outstanding

Proceeds

Outstanding

Proceeds

Series A

1.2378

25.00

6,000,000

147

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

1.4372

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

(5)(6)

4.951

1.2378

1.84

August 15, 2030

25.00

Series B

Series C

6.434

1.6085

2.65

August 15, 2028

25.00

Series D

Series F

(7)

5.749

1.4372

2.63

February 15, 2030

25.00

Series G

Minimum rate reset

(3)(4)

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

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 Company.

(2) On or after the specified redemption dates,

the Company has the option to redeem

for cash the outstanding First Preferred Shares,

in whole or

in part, at the specified per share redemption

value plus all accrued and unpaid dividends

up to but excluding the dates fixed

for redemption.

(3) On the redemption and/or conversion option

date the reset annual dividend per share

will be determined by multiplying $

25.00

per share by

the annual fixed or floating dividend rate, which

for Series A, C, F and H is the sum of the

five-year Government of Canada

Bond Yield on the applicable reset date, plus the applicable

reset dividend yield (Series H annual

reset rate must be a minimum of

4.90

per cent).

(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 B,

D, G and I shares without the consent of

the holder every five years thereafter

for cash, in whole or in

part at a price of $

25.00

per share plus all accrued and unpaid dividends

up to but excluding the date fixed for redemption

and $

25.50

per share

plus all accrued and unpaid dividends up

to but excluding the date fixed for redemption

in the case

of redemptions on any other date after August

15, 2028, February 15, 2025 and August

15, 2028, respectively. The reset dividend yield for Series

I equals the Government of Treasury Bill Rate on the

applicable reset date, plus

2.54

per cent.

(5) On July 9, 2025, Emera announced that

it would not redeem the outstanding Preferred

Shares, Series A or B shares on August

15, 2025.

During the conversion period between

July 16, 2025 and July 31, 2025, subject to

certain conditions, the holders of Series

A shares had the right,

at their option, to convert all or any of their

Series A shares, on a one-for-one basis

into Series B shares and the holders of

Series B Shares had

the right, at their option, to convert all or any

of their Series B shares, on a one-for-one

basis, into Series A Shares. On August

7, 2025, Emera

announced, after having taken into account

all shares tendered for conversion by holders

of its Series A Shares and Series B Shares,

by the end

of the conversion period, the Company had determined

that there would be outstanding less than 1

million Series B Shares on August 15, 2025.

Therefore, in accordance with certain rights,

privileges, restrictions and conditions attaching

to the Series A Shares and the Series B Shares,

the

Company advised the Holders that no Series

A Shares would be converted into Series

B Shares and all remaining Series B Shares

would

automatically be converted into Series A

Shares on a one-for-one basis on August 15,

2025.

(6) On July 16, 2025, Emera announced that

the annual fixed dividend per share for Series

A shares would reset from $0.5456 to $1.2378

for the

five-year period from and including August

14, 2025.

(7) On January 16, 2025, Emera announced

that the annual fixed dividend per share

for Series F shares would reset from $1.0505

to $

1.4372

for

the five-year period from and including February

15, 2025.

(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 30.

meeting.

NON-CONTROLLING INTEREST IN SUBSIDIARIES

As at

December 31

millions of dollars

2025

2024

Preferred shares of GBPC

Authorized:

10,000

non-voting cumulative redeemable variable perpetual

preferred shares.

2025

2024

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.

31. SUPPLEMENTARY

INFORMATION TO CONSOLIDATED

STATEMENTS

CASH FLOWS

For the

Year ended December 31

millions of dollars

2025

2024

Changes in non-cash working capital

Inventory

(63)

Receivables and other current assets

(703)

(154)

Accounts payable

(40)

536

Other current liabilities

Total

non-cash working capital

(757)

452

For the

Year ended December 31

millions of dollars

2025

2024

Supplemental disclosure of cash paid

Interest

1,003

989

Income taxes

Canada - Federal

United States

Total

Income taxes paid

Supplemental disclosure of non-cash activities

Common share dividends reinvested

292

291

Accrued proceeds from disposal of investment subject to significant influence

Decrease in accrued capital expenditures

(54)

Supplemental disclosure of operating activities

Net change in short-term regulatory assets and liabilities ECSPP and Common Shareholders DRIP

277

(118)

32. STOCK-BASED COMPENSATION

Eligible employees can participate in the ECSPP. As of December 31, 2025, 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, 2025, Emera was

in compliance with this requirement.

Compensation cost for shares issued under the ECSPP for the

year ended December 31, 2025 was $

million (2024 – $

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 2025.

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 exercise 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, 2025, Emera was in compliance with

this requirement.

Stock options 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 common 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.

In accordance with the Stock Option Plan, 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 The following table shows the weighted average FV per stock option along with the assumptions

basis.

incorporated into the valuation models for options granted, for

the year-ended December 31:

2025

2024

Weighted average FV per option

6.12

4.66

Expected term

(1)

years

Risk-free interest rate

(2)

2.71

3.56

Expected dividend yield

(3)

5.06

6.11

Expected volatility

(4)

20.90

20.67

(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

2025:

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, 2024

3,796,040

50.53

1,607,490

5.08

Granted

678,000

57.00

678,000

6.25

Exercised

(357,559)

45.57

N/A

Forfeited

N/A

Vested

N/A

(496,710)

4.80

Options outstanding December 31, 2025

4,116,481

52.03

1,788,780

5.60

Options exercisable December 31, 2025

(2)(3)

2,327,701

51.13

(1) As at December 31, 2025, 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 (2024 – $

million,

years).

(2) As at December 31, 2025, the weighted

average remaining term of vested options was

years with an aggregate intrinsic value of

million (2024 –

years, $

million).

(3) As at December 31, 2025, the FV of options

that vested in the year was $

million (2024 – $

million).

Compensation cost recognized for stock options for the year

ended December 31, 2025 was $

million

(2024 – $

million), which was included in “OM&G” on the Consolidated

Statements of Income.

As at December 31, 2025, cash received from option exercises

was $

million (2024 – $

million). The

total intrinsic value of options exercised for the year ended

December 31, 2025 was $

million (2024 – $

million). The range of exercise prices for the options outstanding

as at December 31, 2025 was $

39.93

60.03

(2024 – $

39.93

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 the closing common share price of the last trading day before 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 Under the executive and senior management DSU plan, each participant may elect to defer all or a

redeemed.

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 ten 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, 2025

is presented in the following table:

Employee

DSU

Weighted

Average

Grant Date

Director

DSU

Weighted

Average

Grant Date

Outstanding as at December 31, 2024

789,088

42.65

828,856

47.12

Granted including DRIP

87,985

50.46

120,684

52.04

Exercised

(138,189)

33.16

(188,438)

42.18

Outstanding and exercisable as at December 31, 2025

738,884

45.36

761,102

49.12

Compensation cost recognized for employee and director

DSU’s for the year ended December 31, 2025

was $

million (2024 – $

million). Tax

benefits related to this compensation cost for share units

realized for the year ended December 31, 2025 were $

million (2024 – $

million tax expense). The

aggregate intrinsic value of the outstanding shares for the year

ended December 31, 2025 for employees

was $

million (2024 – $

million). The aggregate intrinsic value of the outstanding

shares for the year

ended December 31, 2025 for directors was $

million (2024 – $

million). Cash payments made

during the year ended December 31, 2025 associated with

the DSU plan were $

million (2024 – $

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, 2025 is presented

in the following table:

Employee PSU

Weighted Average

Grant Date FV

Aggregate intrinsic value

Outstanding as at December 31, 2024

832,093

52.57

Granted including DRIP

332,562

52.61

Exercised

(120,434)

59.77

Forfeited

(134,283)

58.40

Outstanding as at December 31, 2025

909,938

50.77

Compensation cost recognized for the PSU plan for the

year ended December 31, 2025 was $

million

(2024 – $

million). Tax

benefits related to this compensation cost for share

units realized for the year

ended December 31, 2025 were $

million (2024 – $

million). Cash payments made during the year

ended December 31, 2025 associated with the PSU plan were

million (2024 – $

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, 2025 is presented

in the following table:

Employee RSU

Weighted Average

Grant Date FV

Aggregate intrinsic value

Outstanding as at December 31, 2024

653,148

52.36

Granted including DRIP

270,800

52.62

Exercised

(171,274)

59.77

Forfeited

(24,463)

50.79

Outstanding as at December 31, 2025

728,211

50.77

Compensation cost recognized for the RSU plan for the

year ended December 31, 2025 was $

million

(2024 – $

million). Tax

benefits related to this compensation cost for share

units realized for the year

ended December 31, 2025 were $

million (2024 – $

million). Cash payments made during the year

ended December 31, 2025 associated with the RSU plan were

million (2024– $

million).

33. 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 BLPC has established a SIF, primarily for the purpose of building a fund to cover risk against damage and

as an equity investment.

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, 2025

December 31, 2024

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)

462

475

34.

SUBSEQUENT EVENTS

These financial statements and notes reflect the Company’s

evaluation of events occurring subsequent to

the balance sheet date through February 23, 2026, the date

the financial statements were issued.

EX-99.4 6 d845370dex994.htm EX-99.4 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 incorporation by reference in the Registration Statements on Form F-10 (File Nos. 333-291985 and 333-290502), Form F-3 (File No. 333-290501) and Form S-8 (File No. 333-287613) and the use in this Annual Report on Form 40-F of our report dated February 23, 2026, with respect to the consolidated balance sheets of Emera Incorporated as at December 31, 2025 and 2024, 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.

EX-99.5 7 d845370dex995.htm EX-99.5 EX-99.5

Exhibit 99.5

CERTIFICATION

I, Scott C. Balfour, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: February 23, 2026

/s/ Scott C. Balfour

Scott C. Balfour

President & Chief Executive Officer

EX-99.6 8 d845370dex996.htm EX-99.6 EX-99.6

Exhibit 99.6

CERTIFICATION

I, Jared B. Green, certify that:

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

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

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

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

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

Date: February 23, 2026

/s/ Jared B. Green

Jared B. Green

Chief Financial Officer

EX-99.7 9 d845370dex997.htm EX-99.7 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, 2025 (the “Report”), as filed with the U.S. Securities and Exchange Commission, I, Scott C. Balfour, President & Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as enacted pursuant to Section 906 of the U.S. Sarbanes-Oxley Act of 2002, that to my knowledge:

(i)

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

(ii)

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

Date: February 23, 2026

/s/ Scott C. Balfour

Scott C. Balfour

President & Chief Executive Officer

EX-99.8 10 d845370dex998.htm EX-99.8 EX-99.8

Exhibit 99.8

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ENACTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Emera Incorporated (the “Company”) on Form 40-F for the year ended December 31, 2025 (the “Report”), as filed with the U.S. Securities and Exchange Commission, I, Jared B. Green, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as enacted pursuant to Section 906 of the U.S. Sarbanes-Oxley Act of 2002, that to my knowledge:

(i)

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

(ii)

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

Date: February 23, 2026

/s/ Jared B. Green

Jared B. Green

Chief Financial Officer