EX-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

2.9075

2.8775

The accompanying notes are an integral part of these consolidated financial statements.

Emera Incorporated

Consolidated Statements of Comprehensive Income

For the

Year ended December 31

millions of dollars

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

Emera Incorporated

Consolidated Statements of Cash Flows

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

contracts designated under the NPNS exception and will discontinue

the treatment of these contracts

under this exemption if the criteria are no longer met.

Derivatives qualify for hedge accounting if they meet stringent

documentation requirements and can be

proven to effectively hedge identified risk both at

the inception and over the term of the instrument.

Specifically, for cash

flow hedges, change in the FV of derivatives is deferred

to AOCI and recognized in

income in the same period the related hedged item is realized.

Where documentation or effectiveness

requirements are not met, the derivatives are recognized

at FV with any changes in FV recognized in net

income in the reporting period, unless deferred as a result

of regulatory accounting.

Derivatives entered into by NSPI, NMGC and GBPC that

are documented as economic hedges or for

which the NPNS exception has not been taken, are subject

to regulatory accounting treatment. The

change in FV of the derivatives is deferred to a regulatory

asset or liability. The

gain or loss is recognized

in the hedged item when the hedged item is settled. 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

valuation and pricing activities.

In 2025, impairment charges of $

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

estimated future cash outlays.

Stock-Based Compensation

The Company has several stock-based compensation

plans: a common share option plan for senior

management; an employee common share purchase plan;

a deferred share unit (“DSU”) plan; a

performance share unit (“PSU”) plan; and a restricted

share unit (“RSU”) plan. The Company accounts for

its plans in accordance with the FV-based method of

accounting for stock-based compensation. Stock-

based compensation cost is measured at the grant date,

based on the calculated FV of the award, and is

recognized as an expense over the employee’s or

director’s requisite service period using the graded

vesting method. Stock-based compensation plans recognized as

liabilities are initially measured at FV

and re-measured at FV at each reporting date, with the

change in liability recognized in income.

Employee Benefits

The costs of the Company’s pension and other

post-retirement benefit programs for employees are

expensed over the periods during which employees render service.

The Company recognizes the funded

status of its defined-benefit and other post-retirement plans on

the balance sheet and recognizes

changes in funded status in the year the change occurs.

The Company recognizes unamortized gains

and losses and past service costs in “AOCI” or “Regulatory

assets” on the Consolidated Balance Sheets.

The components of net periodic benefit cost other than

the service cost component are included in “Other

income, net” on the Consolidated Statements of Income.

For further 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, $

million ($

million USD)

was recorded in 2025.

Details of the assets and liabilities classified as held for

sale are as follows:

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

obligations through

2040

7. REGULATORY

ASSETS AND LIABILITIES

Regulatory assets represent prudently incurred costs that have

been deferred because it is probable they

will be recovered through future rates or tolls collected from customers.

Management believes existing

regulatory assets are probable for recovery either because

the Company received specific approval from

the applicable regulator, or

due to regulatory precedent established for similar circumstances.

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

clauses.

Base Rates:

On April 2, 2024, TEC filed a rate case with the FPSC for

new base rates. On December 3, 2024, the

FPSC rendered a decision which 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

base.

General Rate Application (“GRA”):

On September 18, 2025, NSPI filed a consensus General Rate

Application (“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

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

per cent.

Base Rates:

On September 14, 2023, NMGC filed a rate case with

the NMPRC for new base rates.

On March 1, 2024,

NMGC filed with the NMPRC a settlement with the support

of all parties in the case for an increase of $

million USD in annual base revenues and maintaining

NMGC’s ROE at

9.375

per cent. The rates reflect

the recovery of increased operating costs and capital investments

in pipeline projects and related

infrastructure, as well as a new customer information and

billing system. NMGC also agreed to withdraw,

and to not reassert in a future rate case application,

its request for a regulatory asset for costs associated

with its 2022 application for a certificate of public convenience

and necessity for a liquefied natural gas

storage facility in New Mexico. The NMPRC approved

the rate case settlement on July 25, 2024. New

rates became effective October 1, 2024.

Fuel Recovery:

NMGC recovers gas supply costs through a PGAC. This

clause recovers actual costs for purchased gas,

gas storage services, interstate pipeline capacity,

and other related items associated with the purchase,

transmission, distribution, and sale of natural gas to its

customers. On a monthly basis, NMGC can adjust

charges based on the next month’s expected cost

of gas and any prior month under-recovery or over-

recovery. The NMPRC

requires that NMGC annually file a reconciliation

of the PGAC period costs and

recoveries. NMGC must file a PGAC Continuation Filing

with the NMPRC every four years to establish

that the continued use of the PGAC is reasonable and

necessary. NMGC

received approval of its PGAC

Continuation in December 2024, for the four-year period

ending December 2028.

Brunswick Pipeline

Brunswick Pipeline is a

145

-kilometre pipeline delivering natural gas from the Saint

John LNG import

terminal near Saint John, New Brunswick to markets in

the northeastern US. Brunswick Pipeline entered

into a

-year firm service agreement commencing in July

2009 with Repsol Energy Canada. The

agreement provides for a predetermined toll increase

in the fifth and fifteenth year of the contract. The

pipeline is considered a Group II pipeline regulated by

the Canada Energy Regulator (“CER”). The CER

Gas Transportation Tariff

is filed by Brunswick Pipeline in compliance with the

requirements of the CER

Act and sets forth the terms and conditions of the transportation

rendered by Brunswick Pipeline.

Other Electric Utilities

BLPC

BLPC is regulated by the Fair Trading

Commission (“FTC”), under the Utilities Regulation (Procedural)

Rules 2003. BLPC is regulated under a cost-of-service model,

with rates set to recover prudently incurred

costs of providing electricity service to customers plus

an appropriate return on capital invested. BLPC’s

approved regulated return on rate base was

per cent for 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

(2,095)

(1,939)

Considering all evidence regarding the utilization of the Company’s

deferred income tax assets, it has

been determined that Emera is more likely than not to realize

all recorded deferred income tax assets,

except for certain loss carryforwards, 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

operating revenues

463

195

Total

gains in net income

467

207

As at December 31, 2025, the Company had the following

notional volumes of outstanding HFT

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

derivatives.

It is possible that volatility in commodity prices could cause

the Company to have material credit risk

exposures with one or more counterparties. If such counterparties

fail to perform their obligations under

one or more agreements, the Company could suffer

a material financial loss. The Company transacts with

counterparties as part of its risk management strategy for managing

commodity price, FX and interest

rate risk. Counterparties that exceed established credit

limits can provide a cash deposit or letter of credit

to the Company for the value in excess of the credit limit where

contractually required. The total cash

deposits/collateral on hand as at December 31, 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

peers.

The Company uses a modelled pricing valuation technique for

determining the FV of Level 3 derivative

instruments. The following table outlines quantitative information

about the significant unobservable

inputs used in the FV measurements categorized within Level

3 of the FV hierarchy:

Significant

Weighted

millions of dollars

Unobservable Input

Low

High

average

(1)

Assets

Liabilities

As at December 31, 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

– $

139

million after-tax loss).

18. RELATED PARTY

TRANSACTIONS

In the ordinary course of business, Emera provides energy

and other services and enters into

transactions with its subsidiaries, associates and other

related companies on terms similar to those

offered to non-related parties. Intercompany balances

and intercompany transactions have been

eliminated on consolidation, except for the net profit on

certain transactions between non-regulated and

regulated entities in accordance with accounting standards

for rate-regulated entities. All material

amounts are under normal interest and credit terms.

Significant transactions between Emera and its associated companies

are as follows:

●

Transactions between NSPI and NSPML

related to the Maritime Link assessment are reported

in the

Consolidated Statements of Income. NSPI’s expense

is reported in Regulated fuel for generation and

purchased power, totalling

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

572

610

As at December 31, 2025, future minimum lease payments

to be received for each of the next five years

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 $

million (2024 – $

million).

23. GOODWILL

The change in goodwill for the year ended December 31

was due to the following:

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

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.

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

meeting.

30. 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

277

(118)

32. STOCK-BASED COMPENSATION

ECSPP and Common Shareholders DRIP

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

basis.

The following table shows the weighted average FV per

stock option along with the assumptions

incorporated into the valuation models for options granted, for

the year-ended December 31:

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

redeemed.

Under the executive and senior management DSU plan, each participant may elect to defer all or a

percentage of their annual incentive award in the form of DSUs with the understanding, for participants

who are subject to executive share ownership guidelines, a minimum of 50 per cent of the value of their

actual annual incentive award (25 per cent in the first year of the program) will be payable in DSUs until

the applicable guidelines are met.

When short-term incentive awards are determined, the amount elected is converted to DSUs, which have

a value equal to the market price of an Emera common share. When a dividend is paid on Emera’s

common shares, each participant’s DSU account is allocated additional DSUs equal in value to the

dividends paid on an equivalent number of Emera common shares. Unless otherwise determined by the

Management Resources and Compensation Committee (“MRCC”), following termination of employment

or retirement, and by December 15 of the calendar year after termination or retirement, the value of the

DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the

participant’s account by the average of Emera’s stock closing price for the 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

as an equity investment.

BLPC has established a SIF,

primarily for the purpose of building a fund to cover risk

against damage and

consequential loss to certain generating, transmission

and distribution systems. ECI holds a variable

interest in the SIF for which it was determined that ECI

was the primary beneficiary and, accordingly,

the

SIF must be consolidated by ECI. In its determination that

ECI controls the SIF,

management considered

that, in substance, the activities of the SIF are being conducted

on behalf of ECI’s subsidiary BLPC and

BLPC, alone, obtains the benefits from the SIF’s

operations. Additionally,

because ECI, through BLPC,

has rights to all the benefits of the SIF,

it is also exposed to the risks related to the activities

of the SIF.

Any withdrawal of SIF fund assets by the Company would

be subject to existing regulations. Emera’s

consolidated VIE in the SIF is recorded as “Other long-term

assets”, “Restricted cash” and “Regulatory

liabilities” on the Consolidated Balance Sheets. Amounts

included in restricted cash represent the cash

portion of funds required to be set aside for the BLPC

SIF.

The Company has identified certain long-term purchase power

agreements that meet the definition of

variable interests as the Company has to purchase all

or a majority of the electricity generation at a fixed

price. However, it was determined

that the Company was not the primary beneficiary

since it lacked the

power to direct the activities of the entity,

including the ability to operate the generating facilities

and make

management decisions.

The following table provides information about Emera’s

portion of material unconsolidated VIEs:

As at

December 31, 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.