EX-99.3

Exhibit 99.3

EMERA INCORPORATED

Consolidated

Financial Statements

December 31,

2024

and 2023

MANAGEMENT REPORT

Management's Responsibility for Financial Reporting

The accompanying consolidated financial statements of Emera

Incorporated and the information in this

annual report are the responsibility of management and have

been approved by the Board of Directors

(“Board”).

The consolidated financial statements have been prepared

by management in accordance with United

States Generally Accepted Accounting Principles. When alternative

accounting methods exist,

management has chosen those it considers most appropriate

in the circumstances. In preparation of

these consolidated financial statements, estimates are sometimes

necessary when transactions affecting

the current accounting period cannot be finalized with

certainty until future periods. Management

represents that such estimates, which have been properly reflected

in the accompanying consolidated

financial statements, are based on careful judgments and

are within reasonable limits of materiality.

Management has determined such amounts on a reasonable

basis in order to ensure that the

consolidated financial statements are presented fairly in

all material respects. Management has prepared

the financial information presented elsewhere in the annual report

and has ensured that it is consistent

with that in the consolidated financial statements.

Emera Incorporated maintains effective systems

of internal accounting and administrative controls,

consistent with reasonable cost. Such systems are designed to

provide reasonable assurance that the

financial information is reliable and accurate, and that

Emera Incorporated's assets are appropriately

accounted for and adequately safeguarded.

The Board is responsible for ensuring that management

fulfils its responsibilities for financial reporting

and is ultimately responsible for reviewing and approving

the consolidated financial statements. The

Board carries out this responsibility principally through its

Audit Committee.

The Audit Committee is appointed by the Board, and its

members are directors who are not officers or

employees of Emera Incorporated. The Audit Committee meets

periodically with management, as well as

with the internal auditors and with the external auditors, to discuss

internal controls over the financial

reporting process, auditing matters and financial reporting

issues, to satisfy itself that each party is

properly discharging its responsibilities, and to review the annual

report, the consolidated financial

statements and the external auditors' report. The Audit

Committee reports its findings to the Board for

consideration when approving the consolidated financial statements

for issuance to the shareholders.

The Audit Committee also considers, for review by the Board

and approval by the shareholders, the

appointment of the external auditors.

The consolidated financial statements have been audited

by Ernst & Young

LLP,

the external auditors, in

accordance with Canadian Generally Accepted Auditing Standards

and with the standards of the Public

Company Accounting Oversight Board. Ernst & Young

LLP has full and free access to the Audit

Committee.

February 21, 2025

“Scott Balfour”

“Gregory Blunden”

President and Chief Executive Officer

Chief Financial Officer

Report of Independent Registered Public Accounting Firm

the Shareholders and the Board of Directors of Emera

Incorporated

Opinion on the Consolidated Financial Statements

We have audited the accompanying Consolidated

Balance Sheets of Emera Incorporated (the

“Company“) as of December 31, 2024 and 2023, the related Consolidated

Statements of Income,

Consolidated Statements of Comprehensive Income,

Consolidated Statements of Changes in Equity and

Consolidated Statements of Cash Flows for the years

then ended, and the related notes (collectively

referred to as the “consolidated financial statements“).

In our opinion, the consolidated financial

statements present fairly,

in all material respects, the consolidated financial position

of the Company as of

December 31, 2024 and 2023, and the consolidated results

of its operations and its consolidated cash

flows for each of the two years in the period ended December

31, 2024, in conformity with United States

generally accepted accounting principles.

Basis for Opinion

These consolidated financial statements are the responsibility

of the Company‘s management. Our

responsibility is to express an opinion on the Company‘s

consolidated financial statements based on our

audits. We are a public accounting firm registered

with the Public Company Accounting Oversight Board

(United States) (“PCAOB”) and are required to be independent

with respect to the Company in

accordance with the U.S. federal securities laws and the

applicable rules and regulations of the Securities

and Exchange Commission and the PCAOB.

We conducted our audits in accordance with

the standards of the PCAOB. Those standards require

that

we plan and perform the audits to obtain reasonable

assurance about whether the consolidated financial

statements are free of material misstatement, whether

due to error or fraud. The Company is not required

to have, nor were we engaged to perform, an audit of its

internal control over financial reporting. As part

of our audits we are required to obtain an understanding

of internal control over financial reporting but not

for the purpose of expressing an opinion on the effectiveness

of the Company's internal control over

financial reporting. Accordingly,

we express no such opinion.

Our audits included performing procedures to assess

the risks of material misstatement of the

consolidated financial statements, whether due to error

or fraud, and performing procedures that respond

to those risks. Such procedures included examining, on a test

basis, evidence regarding the amounts and

disclosures in the consolidated financial statements. Our

audits also included evaluating the accounting

principles used and significant estimates made by management,

as well as evaluating the overall

presentation of the consolidated financial statements. We

believe that our audits provide a reasonable

basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters

arising from the current period audit of the

financial statements that were communicated or required

to be communicated to the audit committee and

that: (1) relate to accounts or disclosures that are material

to the financial statements and (2) involved our

especially challenging, subjective or complex judgments.

The communication of critical audit matters

does not alter in any way our opinion on the consolidated financial

statements, taken as a whole, and we

are not, by communicating the critical audit matters

below, providing separate opinions

on the critical

audit matters or on the accounts or disclosures to which

they relate.

Accounting for the effects of rate regulation

Description

of the Matter

As disclosed in note 7 of the consolidated financial statements,

the Company has $3.4

billion in regulatory assets and $1.9 billion in regulatory

liabilities. The Company’s rate-

regulated subsidiaries are subject to regulation by various

federal, state and provincial

regulatory authorities in the geographic regions in which

they operate. The regulatory

rates are designed to recover the prudently incurred costs

of providing the regulated

products or services and provide a reasonable return on

the equity invested or assets, as

applicable. In addition to regulatory assets and liabilities,

rate regulation impacts multiple

financial statement line items, including, but not limited to,

property, plant

and equipment

(“PP&E”), operating revenues and expenses, income taxes,

and depreciation expense.

Auditing the impact of rate regulation on the Company’s

financial statements is complex

and highly judgmental due to the significant judgments

made by the Company to support

its accounting and disclosure for regulatory matters when

final regulatory decisions or

orders have not yet been obtained or when regulatory

formulas are complex. There is

also subjectivity involved in assessing the potential

impact of future regulatory decisions

on the financial statements. Although the Company

expects to recover costs from

customers through rates, there is a risk that the regulator

will not approve full recovery of

the costs incurred. The Company’s judgments

include making an assessment of the

probability of recovery of and return on costs incurred, of the

potential disallowance of

part of the cost incurred, or of the probable refund of

gains or amounts previously

collected from customers through future rates.

How We

Addressed

the Matter in

Our Audit

We performed audit procedures that included,

amongst others, assessing the Company’s

evaluation of the probability of future recovery for regulatory

assets, PP&E, and refund of

regulatory liabilities by obtaining and reviewing relevant

regulatory orders, filings,

testimony, hearings

and correspondence, and other publicly available

information. For

regulatory matters for which regulatory decisions or orders

have not yet been obtained,

we inspected the rate-regulated subsidiaries’ filings for

any evidence that might contradict

the Company’s assertions, and reviewed other regulatory

orders, filings and

correspondence for other entities within the same or similar

jurisdictions to assess the

likelihood of recovery or refund in future rates based on

the regulator’s treatment of

similar costs under similar circumstances. We obtained

and evaluated an analysis from

the Company and corroborated that analysis with letters

from legal counsel, when

appropriate, regarding cost recoveries, gains or amounts

previously collected from

customers or future changes in rates. We also assessed

the methodology,

accuracy and

completeness of the Company’s calculations of regulatory

asset and liability balances

based on provisions and formulas outlined in rate orders

and other correspondence with

the regulators. We evaluated the Company's

disclosures related to the impacts of rate

regulation.

Fair Value (“FV”) measurement of derivative

financial instruments

Description

of the Matter

Held-for-trading (“HFT”) derivative assets of $270 million

and liabilities of $690 million,

disclosed in note 16 to the consolidated financial statements,

are measured at FV.

The

Company recognized $207 million in realized and unrealized

gains during the year with

respect to HFT derivatives.

Auditing the Company’s valuation of HFT derivatives

is complex and highly judgmental

due to the complexity of the contract terms and valuation models,

and the significant

estimation required in determining the FV of the contracts.

In determining the FV of HFT

derivatives, significant assumptions about future economic

and market assumptions with

uncertain outcomes are used, including third-party sourced

forward commodity pricing

curves based on illiquid markets, internally developed correlation

factors and basis

differentials. These assumptions have a significant

impact on the FV of the HFT

derivatives.

How We

Addressed

the Matter in

Our Audit

We performed audit procedures that included,

amongst others, reviewing executed

contracts and agreements for the identification of inputs

and assumptions impacting the

valuation of derivatives. With the support of our valuation

specialists, we assessed the

methodology and mathematical accuracy of the Company’s

valuation models and

compared the commodity pricing curves used by the Company

to current market and

economic data. For the forward commodity pricing curves,

we compared the Company’s

pricing curves to independently sourced pricing curves.

We also assessed the

methodology and mathematical accuracy of the Company’s

calculations to develop

correlation factors and basis differentials. In

addition, we assessed whether the FV

hierarchy disclosures in note 17 to the consolidated financial

statements were consistent

with the source of the significant inputs and assumptions

used in determining the FV of

derivatives.

/s/

Ernst & Young LLP

Chartered Professional Accountants

We have served as the Company‘s auditor since

1998.

Halifax, Canada

February 21, 2025

Emera Incorporated

Consolidated Statements of Income

For the

Year ended December 31

millions of dollars (except per share amounts)

2024

2023

Operating revenues

Regulated electric

5,872

5,746

Regulated gas

1,575

1,489

Non-regulated

(247)

328

Total

operating revenues (note 6)

7,200

7,563

Operating expenses

Regulated fuel for generation and purchased power

1,992

1,881

Regulated cost of natural gas

396

527

Operating, maintenance and general expenses ("OM&G")

1,918

1,879

Provincial, state, and municipal taxes

427

433

Depreciation and amortization

1,162

1,049

Impairment charges (note 23)

225

Total

operating expenses

6,120

5,769

Income from operations

1,080

1,794

Income from equity investments (note 8)

146

Other income, net (note 9)

203

158

Interest expense, net (note 10)

973

925

Income before provision for income taxes

409

1,173

Income tax (recovery) expense (note 11)

(159)

128

Net income

568

1,045

Non-controlling interest in subsidiaries ("NCI")

Preferred stock dividends

Net income attributable to common shareholders

494

978

Weighted average shares of common stock outstanding (in millions) (note 13)

Basic

289

274

Diluted

289

274

Earnings per common share (note 13)

Basic

1.71

3.57

Diluted

1.71

3.57

Dividends per common share declared

2.8775

2.7875

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

Emera Incorporated

Consolidated Statements of Comprehensive Income

For the

Year ended December 31

millions of dollars

2024

2023

Net income

568

1,045

Other comprehensive income (loss) ("OCI"), net of tax

Foreign currency translation adjustment

(1)

1,027

(270)

Unrealized (losses) gains on net investment hedges

(2)

(139)

Cash flow hedges – reclassification adjustment for gains included in income

(2)

Unrealized gains on available-for-sale investment

Net change in unrecognized pension and post-retirement benefit obligation

(3)

(39)

OCI

(4)

956

(273)

Comprehensive income

1,524

772

Comprehensive income attributable to NCI

Comprehensive Income of Emera Incorporated

1,523

771

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

1) Net of tax expense of $

million for the year ended December 31, 2024 (2023

– $

million recovery).

2) The Company has designated $

1.2

billion United States dollar (USD) denominated

Hybrid Notes as a hedge of the foreign

currency exposure of its net investment in USD

denominated operations.

3) Net of tax expense of

nil

for the year ended December 31, 2024 (2023 – $

million expense).

4) Net of tax expense of $

million for the year ended December 31, 2024 (2023

– $

million recovery).

Emera Incorporated

Consolidated Balance Sheets

As at

December 31

millions of dollars

2024

2023

Assets

Current assets

Cash and cash equivalents

196

567

Restricted cash

Inventory (note 15)

781

790

Derivative instruments (notes 16 and 17)

115

174

Regulatory assets (note 7)

595

339

Receivables and other current assets (note 19)

1,811

1,817

Assets held for sale (note 4)

173

3,688

3,708

Property, plant and equipment ("PP&E"),

net of accumulated depreciation

and amortization of $

10,442

and $

9,994

, respectively (note 21)

26,168

24,376

Other assets

Deferred income taxes (note 11)

392

208

Derivative instruments (notes 16 and 17)

Regulatory assets (note 7)

2,832

2,766

Net investment in direct finance and sales type leases (note 20)

610

621

Investments subject to significant influence (note 8)

654

1,402

Goodwill (note 23)

5,858

5,871

Other long-term assets (note 33)

538

462

Assets held for sale (note 4)

2,160

13,095

11,396

Total assets

42,951

39,480

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

Emera Incorporated

Consolidated Balance Sheets – Continued

As at

December 31

millions of dollars

2024

2023

Liabilities and Equity

Current liabilities

Short-term debt (note 24)

1,400

1,433

Current portion of long-term debt (note 26)

234

676

Accounts payable

1,992

1,454

Derivative instruments (notes 16 and 17)

526

386

Regulatory liabilities (note 7)

262

168

Other current liabilities (note 25)

489

427

Liabilities associated with assets held for sale (note 4)

212

5,115

4,544

Long-term liabilities

Long-term debt (note 26)

18,173

17,689

Deferred income taxes (note 11)

2,331

2,352

Derivative instruments (notes 16 and 17)

118

Regulatory liabilities (note 7)

1,618

1,604

Pension and post-retirement liabilities (note 22)

274

265

Other long-term liabilities (note 8 and 27)

910

820

Liabilities associated with assets held for sale (note 4)

1,148

24,545

22,848

Equity

Common stock (note 12)

9,042

8,462

Cumulative preferred stock (note 29)

1,422

Contributed surplus

Accumulated other comprehensive income ("AOCI') (note 14)

1,261

305

Retained earnings

1,468

1,803

Total

Emera Incorporated equity

13,277

12,074

NCI (note 30)

Total

equity

13,291

12,088

Total liabilities and equity

42,951

39,480

Commitments and contingencies

(note 28)

nil

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

Approved on behalf of the Board of Directors

“Karen Sheriff”

“Scott Balfour”

Chair of the Board

President and Chief Executive Officer

Emera Incorporated

Consolidated Statements of Cash Flows

For the

Year ended December 31

millions of dollars

2024

2023

Operating activities

Net income

568

1,045

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization

1,165

1,060

Income from equity investments, net of dividends

(8)

(22)

Allowance for funds used during construction ("AFUDC") – equity

(53)

(38)

Deferred income taxes, net

(191)

Net change in pension and post-retirement liabilities

(46)

(68)

NSPI fuel adjustment mechanism ("FAM")

451

(88)

Net change in fair value ("FV") of derivative instruments

228

(666)

Net change in regulatory assets and liabilities

(226)

554

Net change in capitalized transportation capacity

175

434

Goodwill impairment charge

214

Gain on sale of LIL, excluding transaction costs

(191)

Other operating activities, net

108

Changes in non-cash working capital (note 31)

452

(95)

Net cash provided by operating activities

2,646

2,241

Investing activities

Additions to PP&E

(3,151)

(2,937)

Proceeds from disposal of investment subject to significant influence

927

Other investing activities

Net cash used in investing activities

(2,218)

(2,917)

Financing activities

Change in short-term debt, net

(66)

Proceeds from short-term debt with maturities greater than 90 days

548

Repayment of short-term debt with maturities greater than 90 days

(1,086)

Proceeds from long-term debt, net of issuance costs

1,361

1,932

Retirement of long-term debt

(1,086)

(151)

Net repayments under committed credit facilities

(825)

(96)

Issuance of common stock, net of issuance costs

284

424

Dividends on common stock

(538)

(488)

Dividends on preferred stock

(73)

(66)

Other financing activities

(12)

Net cash (used in) provided by financing activities

(818)

939

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

cash associated with assets held for sale

(7)

Net (decrease) increase in cash, cash equivalents, restricted cash and cash

associated with assets held for sale

(367)

256

Cash, cash equivalents, and restricted cash, beginning of year

588

332

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

sale, end of year

221

588

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

for sale consists of:

Cash

191

559

Short-term investments

Restricted cash

Assets held for sale

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

sale

221

588

Supplementary Information to Consolidated Statements of Cash Flows (note 31)

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

Emera Incorporated

Consolidated Statements of Changes in Equity

Common

Preferred

Contributed

Retained

Total

Stock

Surplus

AOCI

Earnings

NCI

Equity

millions of dollars

Balance, December 31, 2023

8,462

1,422

305

1,803

12,088

Net income of Emera Inc.

567

568

Other comprehensive income, net of

tax expense of $

million

956

Dividends declared on preferred stock

(note 29)

(73)

Dividends declared on common stock

2.8775

/share)

(829)

Issued under the at-the-market

program ("ATM"), net of after-tax

issuance costs

261

Issued under the Dividend

Reinvestment Program ("DRIP"), net of

discount

291

Senior management stock options

exercised and Employee Common

Share Purchase Plan ("ECSPP")

Other

(1)

Balance, December 31, 2024

9,042

1,422

1,261

1,468

13,291

Balance, December 31, 2022

7,762

1,422

578

1,584

11,441

Net income of Emera Inc.

1,044

1,045

Other comprehensive loss, net of tax

recovery of $

million

(273)

Dividends declared on preferred stock

(note 29)

(66)

Dividends declared on common stock

2.7875

/share)

(759)

Issued under the ATM, net of after-tax

issuance costs

397

Issued under the DRIP, net of discount

272

Senior management stock options

exercised and ECSPP

Other

(1)

Balance, December 31, 2023

8,462

1,422

305

1,803

12,088

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

Emera Incorporated

Notes to the Consolidated Financial Statements

As at December 31, 2024 and 2023

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, 2024, Emera’s reportable segments

include the following:

●

Florida Electric Utility,

which consists of Tampa

Electric (“TEC”), a vertically integrated regulated

electric utility, serving

approximately

855,000

customers in West Central Florida;

●

Canadian Electric Utilities, which includes:

●

Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated

electric utility and the

primary electricity supplier in Nova Scotia, serving approximately

557,000

customers; and

●

100

per cent equity interest in NSP Maritime Link Inc. (“NSPML”),

which developed the

Maritime Link Project, a $

1.8

billion, including AFUDC, transmission project between the

island of Newfoundland and Nova Scotia.

On June 4, 2024, Emera completed the sale of its

31.1

per cent indirect minority equity interest in the

Labrador Island Link Partnership (“LIL”), which was previously

included in the Canadian Electric

Utilities segment. For further details, refer to note 4.

●

Gas Utilities and Infrastructure, which includes:

●

Peoples Gas System Inc. (“PGS”), a regulated gas distribution

utility, serving

approximately

508,000

customers across Florida;

●

New Mexico Gas Company,

Inc. (“NMGC”), a regulated gas distribution utility,

serving

approximately

550,000

customers in New Mexico. On August 5, 2024,

Emera announced an

agreement to sell NMGC. The transaction is expected to

close in late 2025, subject to certain

approvals, including approval by the New Mexico Public

Regulation Commission (“NMPRC”).

For further details, refer to note 4.

●

Emera Brunswick Pipeline Company Limited (“Brunswick

Pipeline”), a

145

-kilometre pipeline

delivering re-gasified liquefied natural gas from Saint John,

New Brunswick to the United

States (“US”) border under a

-year firm service agreement with Repsol Energy

North

America Canada Partnership (“Repsol Energy Canada”),

which expires in 2034;

●

SeaCoast Gas Transmission, LLC (“SeaCoast”),

a regulated intrastate natural gas

transmission company offering services in Florida;

and

●

12.9

per cent equity interest in Maritimes & Northeast

Pipeline (“M&NP”), a

1,400

-kilometre

pipeline that transports natural gas throughout markets

in Atlantic Canada and the

northeastern US.

●

Other Electric Utilities, which includes Emera (Caribbean)

Incorporated (“ECI”), a holding company

with regulated electric utilities that include:

●

The Barbados Light & Power Company Limited (“BLPC”),

a vertically integrated regulated

electric utility on the island of Barbados, serving approximately

135,000

customers;

●

Grand Bahama Power Company Limited (“GBPC”), a vertically

integrated regulated electric

utility on Grand Bahama Island, serving approximately

19,500

customers; and

●

19.5

per cent equity interest in St. Lucia Electricity Services

Limited (“Lucelec”), a vertically

integrated regulated electric utility on the island of St.

Lucia.

●

Emera’s other segment includes investments in

energy-related non-regulated companies that are

below the required threshold for reporting as separate

segments and corporate expense and revenue

items that are not directly allocated to the operations of Emera’s

subsidiaries and investments. This

includes:

●

Emera Energy, which

consists of:

●

Emera Energy Services (“EES”), a physical energy business

that purchases and sells

natural gas and electricity and provides related energy

asset management services;

●

Brooklyn Power Corporation (“Brooklyn Energy”), a

MW biomass co-generation

electricity facility in Brooklyn, Nova Scotia; and

●

50.0

per cent joint venture interest in Bear Swamp Power

Company LLC (“Bear

Swamp”), a

660

MW pumped storage hydroelectric facility in northwestern

Massachusetts.

●

Emera US Finance LP (“Emera Finance”), EUSHI Finance, Inc.

and TECO Finance, Inc.

(“TECO Finance”), financing subsidiaries of Emera;

●

Emera US Holdings Inc., a wholly owned holding company

for certain of Emera’s assets

located in the US; and

●

Other investments.

Basis of Presentation

These consolidated financial statements are prepared

and presented in accordance with United States

Generally Accepted Accounting Principles (“USGAAP”)

and, in the opinion of management, include all

adjustments that are of a recurring nature and necessary

to fairly state the financial position of Emera.

All dollar amounts are presented in Canadian dollars (“CAD”),

unless otherwise indicated.

Principles of Consolidation

These consolidated financial statements include the accounts

of Emera Incorporated, its majority-owned

subsidiaries, and a variable interest entity (“VIE”) in which

Emera is the primary beneficiary.

Emera uses

the equity method of accounting to record investments

in which the Company has the ability to exercise

significant influence, and for VIEs in which Emera is not

the primary beneficiary.

The Company performs ongoing analysis to assess whether

it holds any VIEs or whether any

reconsideration events have arisen with respect to existing

VIEs.

identify potential VIEs, management

reviews contractual and ownership arrangements such

as leases, long-term purchase power agreements,

tolling contracts, guarantees, jointly owned facilities and

equity investments. VIEs of which the Company

is deemed the primary beneficiary must be consolidated.

The primary beneficiary of a VIE has both the

power to direct the activities of the VIE that most significantly

impacts its economic performance and the

obligation to absorb losses or the right to receive benefits

of the VIE that could potentially be significant to

the VIE. In circumstances where Emera has an investment

in a VIE but is not deemed the primary

beneficiary, the VIE

is accounted for using the equity method. For further

details on VIEs, refer to note 33.

Intercompany balances and transactions have been

eliminated on consolidation, except for the net profit

on certain transactions between certain non-regulated and regulated

entities in accordance with

accounting standards for rate-regulated entities. The net profit

on these transactions, which would be

eliminated in the absence of the accounting standards

for rate-regulated entities, is recorded in non-

regulated operating revenues. An offset is recorded

to PP&E, regulatory assets, regulated fuel for

generation and purchased power,

or OM&G, depending on the nature of the transaction.

Use of Management Estimates

The preparation of consolidated financial statements

in accordance with USGAAP requires management

to make estimates and assumptions. These may affect

reported amounts of assets and liabilities at the

date of the financial statements and reported amounts

of revenues and expenses during the reporting

periods. Significant areas requiring use of management

estimates relate to rate-regulated assets and

liabilities, accumulated reserve for cost of removal, pension

and post-retirement benefits, unbilled

revenue, useful lives for depreciable assets, goodwill and long-lived

assets impairment assessments,

income taxes, asset retirement obligations (“ARO”), and

valuation of financial instruments. Management

evaluates the Company’s estimates on an ongoing

basis based upon historical experience, current and

expected conditions and assumptions believed to be reasonable

at the time the assumption is made, with

any adjustments recognized in income in the year they arise.

Regulatory Matters

Regulatory accounting applies where rates are established

by, or subject to

approval by, an

independent

third-party regulator. Rates

are designed to recover prudently incurred costs of providing

regulated

products or services and provide an opportunity for a reasonable

rate of return on invested capital, as

applicable. For further detail, refer to note 7.

Foreign Currency Translation

Monetary assets and liabilities denominated in foreign

currencies are converted to CAD at the rates of

exchange prevailing at the balance sheet date. The resulting differences

between the translation at the

original transaction date and the balance sheet date are

included in income.

Assets and liabilities of foreign operations whose functional

currency is not the Canadian dollar are

translated using exchange rates in effect at the balance

sheet date and the results of operations at the

average exchange rate in effect for the period. The

resulting exchange gains and losses on the assets

and liabilities are deferred on the balance sheet in AOCI.

The Company designates certain USD denominated debt

held in CAD functional currency companies as

hedges of net investments in USD denominated foreign

operations. The change in the carrying amount of

these investments, measured at exchange rates in effect

at the balance sheet date, is recorded in OCI.

Revenue Recognition

Regulated Electric and Gas Revenue:

Electric and gas revenues, including energy charges, demand

charges, basic facilities charges and

clauses and riders, are recognized when obligations under the

terms of a contract are satisfied, which is

when electricity and gas are delivered to customers over

time as the customer simultaneously receives

and consumes the benefits. Electric and gas revenues

are recognized on an accrual basis and include

billed and unbilled revenues. Revenues related to the

sale of electricity and gas are recognized at rates

approved by the respective regulators and recorded

based on metered usage, which occurs on a

periodic, systematic basis, generally monthly or bi-monthly.

At the end of each reporting period, electricity

and gas delivered to customers, but not billed, is estimated

and corresponding unbilled revenue is

recognized. The Company’s estimate of unbilled

revenue at the end of the reporting period

is calculated

by estimating the megawatt hours (“MWh”) or therms delivered

to customers at the established rates

expected to prevail in the upcoming billing cycle. This

estimate includes assumptions as to the pattern of

energy demand, weather, line

losses and inter-period changes to customer classes.

Non-regulated Revenue:

Marketing and trading margins are comprised of Emera

Energy’s corresponding purchases and sales

natural gas and electricity,

pipeline capacity costs and energy asset management

revenues. Revenues

are recorded when obligations under terms of the contract

are satisfied and are presented on a net basis

reflecting the nature of contractual relationships with customers

and suppliers.

Energy sales are recognized when obligations under the

terms of the contracts are satisfied, which is

when electricity is delivered to customers over time.

Other non-regulated revenues are recorded when obligations

under the terms of the contract are

satisfied.

Other:

Sales, value add, and other taxes, except for gross receipts

taxes discussed below,

collected by the

Company concurrent with revenue-producing activities

are excluded from revenue.

Franchise Fees and Gross Receipts

TEC and PGS recover from customers certain costs incurred,

on a dollar-for-dollar basis, through prices

approved by the Florida Public Service Commission (“FPSC”).

The amounts included in customers’ bills

for franchise fees and gross receipt taxes are included

as “Regulated electric” and “Regulated gas”

revenues in the Consolidated Statements of Income.

Franchise fees and gross receipt taxes payable by

TEC and PGS are included as an expense on the Consolidated

Statements of Income in “Provincial, state

and municipal taxes”.

NMGC is an agent in the collection and payment of franchise

fees and gross receipt taxes and is not

required by a tariff to present the amounts on

a gross basis. Therefore, NMGC’s franchise

fees and gross

receipt taxes are presented net with no line item impact

on the Consolidated Statements of Income.

PP&E

PP&E is recorded at original cost, including AFUDC or

capitalized interest, net of contributions received in

aid of construction.

The cost of additions, including betterments and replacements

of units, are included in “PP&E” on the

Consolidated Balance Sheets. When units of regulated PP&E

are replaced, renewed or retired, their cost,

plus removal or disposal costs, less salvage proceeds,

is charged to accumulated depreciation, with no

gain or loss reflected in income. Where a disposition of

non-regulated PP&E occurs, gains and losses are

included in income as the dispositions occur.

The cost of PP&E represents the original cost of materials,

contracted services, direct labour,

AFUDC for

regulated property or interest for non-regulated property,

ARO, and overhead attributable to the capital

project. Overhead includes corporate costs such as finance,

information technology and labour costs,

along with other costs related to support functions, employee

benefits, insurance, procurement, and fleet

operating and maintenance. Expenditures for project development

are capitalized if they are expected to

have a future economic benefit.

Normal maintenance projects and major maintenance

projects that do not increase overall life of the

related assets are expensed as incurred. When a major

maintenance project increases the life or value of

the underlying asset, the cost is capitalized.

Depreciation is determined by the straight-line method, based

on the estimated remaining service lives of

the depreciable assets in each functional class of depreciable

property. For some

of Emera’s rate-

regulated subsidiaries, depreciation is calculated using

the group remaining life method, which is applied

to the average investment, adjusted for anticipated costs

of removal less salvage, in functional classes of

depreciable property.

The service lives of regulated assets require

regulatory approval.

Intangible assets, which are included in “PP&E” on the Consolidated

Balance Sheets, consist primarily of

computer software and land rights. Amortization is determined

by the straight-line method, based on the

estimated remaining service lives of the asset in each category.

For some of Emera’s rate-regulated

subsidiaries, amortization is calculated using the amortizable

life method which is applied to the net book

value to date over the remaining life of those assets. The

service lives of regulated intangible assets

require regulatory approval.

Goodwill

Goodwill is calculated as the excess of the purchase price

of an acquired entity over the estimated FV of

identifiable assets acquired and liabilities assumed at the

acquisition date. Goodwill is carried at initial

cost less any write-down for impairment and is adjusted

for the impact of foreign exchange (“FX”).

Goodwill is subject to assessment for impairment at the

reporting unit level annually,

or if an event or

change in circumstances indicates that the FV of a reporting

unit may be below its carrying value. When

assessing goodwill for impairment, the Company has the option

of first performing a qualitative

assessment to determine whether a quantitative assessment

is necessary. In

performing a qualitative

assessment management considers, among other factors,

macroeconomic conditions, industry and

market considerations and overall financial performance.

If the Company performs a qualitative assessment and

determines it is more likely than not that its FV is

less than its carrying amount, or if the Company chooses

to bypass the qualitative assessment, a

quantitative test is performed. The quantitative test compares

the FV of the reporting unit to its carrying

value, including goodwill (“carrying amount”). If the carrying

amount of the reporting unit exceeds its FV,

an impairment loss is recorded. Management estimates

the FV of the reporting unit by using the income

approach, or a combination of the income and market

approach. The income approach uses a discounted

cash flow analysis which relies on management’s

best estimate of the reporting unit’s projected

cash

flows. The analysis includes an estimate of terminal values

based on these expected cash flows using a

methodology which derives a valuation using an assumed

perpetual annuity based on the reporting unit’s

residual cash flows. The discount rate used is a market participant

rate based on a peer group of publicly

traded comparable companies and represents the weighted

average cost of capital of comparable

companies. For the market approach, management estimates

FV based on comparable companies and

transactions within comparable industries, or in the case

of the NMGC quantitative assessment in 2024,

transactions involving the reporting unit. Significant assumptions

used in estimating the FV of a reporting

unit using an income approach include discount and growth

rates, rate case assumptions including future

cost of capital, valuation of the reporting unit’s net

operating loss (“NOL”) and projected operating

and

capital cash flows. Adverse changes in these assumptions

could result in a future material impairment of

the goodwill assigned to Emera’s reporting units.

As of December 31, 2024, Emera’s goodwill represented

the excess of the acquisition purchase price for

TECO Energy, Inc.

(TEC, PGS and NMGC reporting units) over the FV

assigned to identifiable assets

acquired and liabilities assumed. In Q3 2024, Emera entered

into an agreement to sell NMGC. As a

result, a quantitative goodwill impairment assessment

was performed on the NMGC reporting unit and the

Company recorded a goodwill impairment charge of $

210

million ($

198

million, after-tax) or $

155

million

USD ($

146

million USD, after-tax). The reduced NMGC goodwill

balance of $

303

million is included in the

NMGC disposal unit classified as held for sale. For further

details, refer to note 23.

In Q4 2024, a qualitative assessment was performed for

TEC given the significant excess of FV over

carrying amounts calculated during the last quantitative test

in Q4 2023. Management concluded it was

more likely than not that the FV of this reporting unit exceeded

its carrying amount, including goodwill. As

such, no quantitative testing was required. Given the length

of time passed since the last quantitative

impairment test for the PGS reporting unit, Emera elected

to bypass a qualitative assessment and

performed a quantitative impairment assessment in Q4

2024 using a combination of the income and

market approach. This assessment estimated that the

FV of the PGS reporting unit exceeded its carrying

amount, including goodwill, and as a result, no impairment

charges were recognized.

Income Taxes and

Investment Tax

Credits

Emera recognizes deferred income tax assets and liabilities

for the future tax consequences of events

that have been included in financial statements or income tax

returns. Deferred income tax assets and

liabilities are determined based on the difference

between the carrying value of assets and liabilities on

the Consolidated Balance Sheets, and their respective

tax bases using enacted tax rates in effect

for the

year in which the differences are expected to reverse.

The effect of a change in income tax rates on

deferred income tax assets and liabilities is recognized

in earnings in the period when the change is

enacted, unless required to be offset to a regulatory

asset or liability by law or by order of the regulator.

Emera recognizes the effect of income tax positions

only when it is more likely than not that they will be

realized. Management reviews all readily available current and

historical information, including forward-

looking information, and the likelihood that deferred income

tax assets will be recovered from future

taxable income is assessed and assumptions are made

about the expected timing of reversal of deferred

income tax assets and liabilities. If management subsequently

determines it is likely that some or all of a

deferred income tax asset will not be realized, a valuation

allowance is recorded to reflect the amount of

deferred income tax asset expected to be realized.

Generally, investment

tax credits are recorded as a reduction to income

tax expense in the current or

future periods to the extent that realization of such benefit

is more likely than not. Investment tax credits

earned on regulated assets by TEC, PGS and NMGC are

deferred and amortized as required by

regulatory practices.

TEC, PGS, NMGC and BLPC collect income taxes from

customers based on current and deferred income

taxes. NSPI, NSPML and Brunswick Pipeline collect income taxes

from customers based on income tax

that is currently payable, except for the deferred income taxes

on certain regulatory balances specifically

prescribed by regulators. For the balance of regulated

deferred income taxes, NSPI, NSPML and

Brunswick Pipeline recognize regulatory assets or liabilities

where the deferred income taxes are

expected to be recovered from or returned to customers

in future years. These regulated assets or

liabilities are grossed up using the respective income tax

rate to reflect the income tax associated with

future revenues that are required to fund these deferred

income tax liabilities, and the income tax benefits

associated with reduced revenues resulting from the realization

of deferred income tax assets. GBPC is

not subject to income taxes.

Emera classifies interest and penalties associated with

unrecognized tax benefits as interest and

operating expense, respectively.

For further detail, refer to note 11.

Derivatives and Hedging Activities

The Company manages its exposure to normal operating and

market risks relating to commodity prices,

FX, interest rates and share prices through contractual

protections with counterparties where practicable,

and by using financial instruments consisting mainly of

FX forwards and swaps, interest rate options and

swaps, equity derivatives, and coal, oil and gas futures,

options, forwards and swaps. In addition, the

Company has contracts for the physical purchase and sale of

natural gas. These physical and financial

contracts are classified as HFT.

Collectively, these contracts

and financial instruments are considered

derivatives.

The Company recognizes the FV of all its derivatives on

its balance sheet, except for non-financial

derivatives that meet the normal purchases and normal sales

(“NPNS”) exception. Physical contracts that

meet the NPNS exception are not recognized on the balance

sheet; these contracts are recognized in

income when they settle. A physical contract generally

qualifies for the NPNS exception if the transaction

is reasonable in relation to the Company’s business

needs, the counterparty owns or controls resources

within the proximity to allow for physical delivery,

the Company intends to receive physical delivery of the

commodity, and the

Company deems the counterparty creditworthy.

The Company continually assesses

contracts designated under the NPNS exception and will discontinue

the treatment of these contracts

under this exemption if the criteria are no longer met.

Derivatives qualify for hedge accounting if they meet stringent

documentation requirements and can be

proven to effectively hedge identified risk both at

the inception and over the term of the instrument.

Specifically, for cash

flow hedges, change in the FV of derivatives is deferred

to AOCI and recognized in

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

Where documentation or effectiveness

requirements are not met, the derivatives are recognized

at FV with any changes in FV recognized in net

income in the reporting period, unless deferred as a result

of regulatory accounting.

Derivatives entered into by NSPI, NMGC and GBPC that

are documented as economic hedges or for

which the NPNS exception has not been taken, are subject

to regulatory accounting treatment. The

change in FV of the derivatives is deferred to a regulatory

asset or liability. The

gain or loss is recognized

in the hedged item when the hedged item is settled. Management

believes any gains or losses resulting

from settlement of these derivatives related to fuel for

generation and purchased power will be refunded

to or collected from customers in future rates. TEC and PGS

have no derivatives related to hedging.

Derivatives that do not meet any of the above criteria are

designated as HFT,

with changes in FV

normally recorded in net income of the period. The Company

has not elected to designate any derivatives

to be included in the HFT category where another accounting

treatment would apply.

Emera classifies gains and losses on derivatives as a component

of non-regulated operating revenues,

fuel for generation and purchased power,

other expenses, inventory,

and OM&G, depending on the

nature of the item being economically hedged. Transportation

capacity arising as a result of marketing

and trading derivative transactions is recognized as an asset

in “Receivables and other current assets”

and amortized over the period of the transportation contract

term. Cash flows from derivative activities are

presented in the same category as the item being hedged within

operating activities on the Consolidated

Statements of Cash Flows. Non-hedged derivatives are included

in operating cash flows on the

Consolidated Statements of Cash Flows.

Derivatives, as reflected on the Consolidated Balance

Sheets, are not offset by the FV amounts of cash

collateral with the same counterparty.

Rights to reclaim cash collateral are recognized

in “Receivables

and other current assets” and obligations to return cash

collateral are recognized in “Accounts payable”.

Leases

The Company determines whether a contract contains

a lease at inception by evaluating whether the

contract conveys the right to control the use of an identified

asset for a period of time in exchange for

consideration.

Emera has leases with independent power producers (“IPP”)

and other utilities for annual requirements to

purchase wind and hydro energy over varying contract

lengths which are classified as finance leases.

These finance leases are not recorded on the Company’s

Consolidated Balance Sheets as payments

associated with the leases are variable in nature and there

are no minimum fixed lease payments. Lease

expense associated with these leases is recorded as “Regulated

fuel for generation and purchased

power” on the Consolidated Statements of Income.

Operating lease liabilities and right-of-use assets are recognized

on the Consolidated Balance Sheets

based on the present value of the future minimum lease payments

over the lease term at commencement

date. As most of Emera’s leases do not provide

an implicit rate, the incremental borrowing rate

commencement of the lease is used in determining

the present value of future lease payments. Lease

expense is recognized on a straight-line basis over the

lease term and is recorded as “OM&G” on the

Consolidated Statements of Income.

Where the Company is the lessor,

a lease is a sales-type lease if certain criteria are met

and the

arrangement transfers control of the underlying asset

to the lessee. For arrangements where the criteria

are met due to the presence of a third-party residual value

guarantee, the lease is a direct financing

lease.

For direct finance leases, a net investment in the lease

is recorded that consists of the sum of the

minimum lease payments and residual value, net of estimated

executory costs and unearned income.

The difference between the gross investment

and the cost of the leased item is recorded as unearned

income at the inception of the lease. Unearned income

is recognized in income over the life of the lease

using a constant rate of interest equal to the internal

rate of return on the lease.

For sales-type leases, the accounting is similar to the accounting

for direct finance leases however,

the

difference between the FV and the carrying value

of the leased item is recorded at lease commencement

rather than deferred over the term of the lease.

Emera has certain contractual agreements that include lease and non-lease components, which

management has elected to account for as a single lease component.

Cash, Cash Equivalents and Restricted Cash

Cash equivalents consist of highly liquid short-term investments

with original maturities of three months or

less at acquisition.

Receivables and Allowance for Credit Losses

Utility customer receivables are recorded at the invoiced

amount and do not bear interest. Standard

payment terms for electricity and gas sales are approximately

30 days. A late payment fee may be

assessed on account balances after the due date. The

Company recognizes allowances for credit losses

to reduce accounts receivable for amounts expected to

be uncollectable. Management estimates credit

losses related to accounts receivable by considering historical

loss experience, customer deposits,

current events, the characteristics of existing accounts

and reasonable and supportable forecasts that

affect the collectability of the reported amount.

Provisions for credit losses on receivables are expensed

to maintain the allowance at a level considered adequate

to cover expected losses. Receivables are

written off against the allowance when they are

deemed uncollectible.

Inventory

Fuel and materials inventories are valued at the lower

of weighted-average cost or net realizable value,

unless evidence indicates the weighted-average cost

will be recovered in future customer rates.

Asset Impairment

Long-Lived Assets:

Emera assesses whether there has been an impairment

of long-lived assets and intangibles when a

triggering event occurs, such as a significant market disruption

or sale of a business.

The assessment involves comparing undiscounted expected

future cash flows to the carrying value of the

asset. When the undiscounted cash flow analysis indicates

a long-lived asset is not recoverable, the

amount of the impairment loss is determined by measuring

the excess of the carrying amount of the long-

lived asset over its estimated FV.

The Company’s assumptions relating to future

results of operations or

other recoverable amounts, are based on a combination

of historical experience, fundamental economic

analysis, observable market activity and independent market

studies. The Company’s expectations

regarding uses and holding periods of assets are based

on internal long-term budgets and projections,

which consider external factors and market forces, as

of the end of each reporting period. The

assumptions made are consistent with generally accepted

industry approaches and assumptions used for

valuation and pricing activities.

In 2024, impairment charges of $

million ($

million after-tax) were recognized on certain assets,

million of which was included in Other income, net with $

million included in Impairment charges on the

Consolidated Income Statement.

impairment charges related to long-lived assets were recognized

2023.

Equity Method Investments:

The carrying value of investments accounted for under

the equity method are assessed for impairment by

comparing the FV of these investments to their carrying values,

if a FV assessment was completed, or by

reviewing for the presence of impairment indicators. If

an impairment exists, and it is determined to be

other-than-temporary,

a charge is recognized in earnings equal to the

amount the carrying value exceeds

the investment’s FV.

impairment of equity method investments was required

in either 2024 or 2023.

Financial Assets:

Equity investments, other than those accounted for under

the equity method, are measured at FV,

with

changes in FV recognized in the Consolidated Statements of Income.

Equity investments that do not

have readily determinable FV are recorded at cost minus

impairment, if any,

plus or minus changes

resulting from observable price changes in orderly transactions

for the identical or similar investments.

impairment of financial assets was required in either

2024 or 2023.

Asset Retirement Obligations

An ARO is recognized if a legal obligation exists in connection

with the future disposal or removal costs

resulting from the permanent retirement, abandonment

or sale of a long-lived asset. A legal obligation

may exist under an existing or enacted law or statute,

written or oral contract, or by legal construction

under the doctrine of promissory estoppel.

An ARO represents the FV of estimated cash flows necessary

to discharge the future obligation, using

the Company’s credit adjusted risk-free rate. The

amounts are reduced by actual expenditures incurred.

Estimated future cash flows are based on completed depreciation

studies, remediation reports, prior

experience, estimated useful lives, and governmental regulatory

requirements. The present value of the

liability is recorded and the carrying amount of the related long-lived

asset is correspondingly increased.

The amount capitalized at inception is depreciated in the same

manner as the related long-lived asset.

Over time, the liability is accreted to its estimated future value.

AROs are included in “Other long-term

liabilities” and accretion expense is included as part of

“Depreciation and amortization”. Any regulated

accretion expense not yet approved by the regulator is

recorded in “PP&E” and included in the next

depreciation study.

Some of the Company’s transmission and distribution

assets may have conditional AROs that are not

recognized in the consolidated financial statements, as

the FV of these obligations could not be

reasonably estimated, given insufficient information

to do so. A conditional ARO refers to a legal

obligation to perform an asset retirement activity in which

the timing and/or method of settlement are

conditional on a future event that may or may not be

within the control of the entity.

Management

monitors these obligations and a liability is recognized at FV

in the period in which an amount can be

determined.

Cost of Removal (“COR”)

TEC, PGS, NMGC and NSPI recognize non-ARO COR

as regulatory liabilities or regulatory assets. The

non-ARO COR represent funds received from customers

through depreciation rates to cover estimated

future non-legally required COR of PP&E upon retirement. The

companies accrue for COR over the life of

the related assets based on depreciation studies approved

by their respective regulators. The costs are

estimated based on historical experience and future

expectations, including expected timing and

estimated future cash outlays.

Stock-Based Compensation

The Company has several stock-based compensation

plans: a common share option plan for senior

management; an employee common share purchase plan;

a deferred share unit (“DSU”) plan; a

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

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

its plans in accordance with the FV-based method of

accounting for stock-based compensation. Stock-

based compensation cost is measured at the grant date,

based on the calculated FV of the award, and is

recognized as an expense over the employee’s or

director’s requisite service period using the graded

vesting method. Stock-based compensation plans recognized as

liabilities are initially measured at FV

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

change in liability recognized in income.

Employee Benefits

The costs of the Company’s pension and other

post-retirement benefit programs for employees are

expensed over the periods during which employees render service.

The Company recognizes the funded

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

the balance sheet and recognizes

changes in funded status in the year the change occurs.

The Company recognizes unamortized gains

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

assets” on the Consolidated Balance Sheets.

The components of net periodic benefit cost other than

the service cost component are included in “Other

income, net” on the Consolidated Statements of Income.

For further detail, refer to note 22.

Government Grants

The Company accounts for government grants by applying

a grant accounting model by analogy to

International Accounting Standards (“IAS”) 20, Accounting

for Government Grants and Disclosure of

Government Assistance. A grant relating to an asset is

reflected in the determination of the carrying

amount of the asset. A grant relating to income is presented

as a deduction from the related expense it is

intended to compensate.

In 2024, the Company received an aggregate of $

million (2023 – $

million) of government grants from

various Canadian and US government agencies towards

capital projects included in

PP&E

. The capital

projects receiving grants primarily relate to the Company’s

decarbonization and environmental

compliance initiatives. Further details on significant grant programs

utilized in 2024 and 2023 are noted

below.

Natural Resources Canada (“NRCan”) Smart Renewables

& Electrification Pathways (“SREP”):

On March 27, 2024, NSPI was approved for a grant under the

NRCan SREPs to fund the construction of

three

50 MW battery storage systems in Nova Scotia.

NSPI can make claims under the grant for

per

cent of eligible project costs to a maximum $

109

million. Eligible costs can be incurred until March

31,

2027. For the year-end December 31, 2024, NSPI received

million (2023 –

nil

) in funding under the

grant, which has been recorded as a reduction to the carrying

amount of the project in

PP&E

CHANGE IN ACCOUNTING POLICY

The new USGAAP accounting policy that is applicable

to, and adopted by the Company in 2024, is

described as follows:

Improvements to Reportable Segment Disclosures

The Company adopted Accounting Standard Update (“ASU”) 2023-07,

Segment Reporting (Topic

280),

Improvements to Reportable Segment Disclosures. The change

in the standard improves reportable

segment disclosure requirements, primarily through enhanced

disclosures about significant segment

expenses. The changes improve financial reporting by

requiring disclosure of incremental segment

information on an annual and interim basis for all public

entities to enable investors to develop more

decision-useful financial analyses. The guidance was

effective for annual reporting periods beginning

after December 15, 2023, and for interim periods beginning

after December 15, 2024. Adoption of the

standard resulted in additional qualitative disclosures provided

in note 5.

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.

Disaggregation of Income Statement Expenses

In November 2024, the FASB

issued ASU 2024-03, Income Statement Reporting–Comprehensive

Income–Expense Disaggregation Disclosures (Subtopic

220-40): Disaggregation of Income Statement

Expenses. The standard update improves the disclosures about

a public business entity’s expenses by

requiring more detailed information about the types of

expenses (including purchases of inventory,

employee compensation, depreciation and amortization)

included within income statement expense

captions. The guidance will be effective for annual

reporting periods beginning after December 15, 2026,

and interim reporting periods beginning after December

15, 2027. Early adoption is permitted. The

standard updates are to be applied prospectively with the option

for retrospective application. The

Company is currently evaluating the impact of adoption

of the standard update on its consolidated

financial statements disclosures.

Improvements to Income Tax

Disclosures

In December 2023, the FASB

issued ASU 2023-09, Income Taxes

(Topic

740): Improvements to Income

Tax

Disclosures. The standard enhances the transparency,

decision usefulness and effectiveness of

income tax disclosures by requiring consistent categories

and greater disaggregation of information in the

reconciliation of income taxes computed using the enacted

statutory income tax rate to the actual income

tax provision and effective income tax rate, as well

as the disaggregation of income taxes paid (refunded)

by jurisdiction. The standard also requires disclosure of income

(loss) before provision for income taxes

and income tax expense (recovery) in accordance with

U.S. Securities and Exchange Commission

Regulation S-X 210.4-08(h), Rules of General Application

– General Notes to Financial Statements:

Income Tax

Expense, and the removal of disclosures no longer considered

cost beneficial or relevant.

The guidance will be effective for annual reporting periods

beginning after December 15, 2024. Early

adoption is permitted. The standard will be applied on

a prospective basis, with retrospective application

permitted. The Company is currently evaluating the impact of

adoption of the standard on its consolidated

financial statements disclosures.

DISPOSITIONS

Pending Sale of NMGC

On August 5, 2024, Emera entered into an agreement

to sell its indirect wholly owned subsidiary NMGC

for a total enterprise value of approximately $

1.3

billion USD, consisting of cash proceeds and the

transfer of debt and customary closing adjustments. The

transaction is expected to close in late 2025,

subject to certain approvals, including approval by the

NMPRC. As a result of the pending sale, NMGC’s

assets and liabilities are classified as held for sale.

As the transaction proceeds will be lower than the carrying amount

of the assets and liabilities being sold,

Emera assessed the NMGC reporting unit for goodwill impairment

by comparing the FV of expected

transaction proceeds to the carrying value of net assets,

including goodwill of $

366

million USD (“NMGC

carrying amount”). The goodwill of the reporting unit was

determined to be impaired and a non-cash

goodwill impairment charge of $

210

million ($

198

million, after-tax) or $

155

million USD ($

146

million

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

Statements of Income in Q3

2024.

Following the goodwill impairment assessment, the held for

sale assets and liabilities were measured at

the lower of their carrying amount or fair value less costs

to sell. The measurement resulted in an

additional loss for the estimated future transaction costs

of $

million ($

million after-tax), in addition to

incurred transaction costs of $

million ($

million after-tax) recorded in “Other Income, net” on the

Consolidated Statements of Income in Q3 2024.

The Company will continue to record depreciation on the NMGC

assets through the transaction closing

date, as the depreciation continues to be reflected in

customer rates and will be reflected in the carryover

basis of the assets when sold. Depreciation and amortization

of $

million ($

million USD) was

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

they were classified as held for sale, through

December 31, 2024.

Details of the assets and liabilities classified as held for

sale are as follows:

As at

December 31

millions of dollars

2024

Cash and cash equivalents

Inventory

Derivative instruments

Regulatory assets

Receivables and other current assets

127

Current assets held for sale

173

PP&E

1,828

Regulatory assets

Goodwill

303

Other long-term assets

Long-term assets held for sale

2,160

Total assets held for sale

2,333

Short-term debt

Derivative instruments

Regulatory liabilities

Accounts payable and other current liabilities

155

Current liabilities associated with assets held for sale

212

Long-term debt

696

Deferred income taxes

167

Regulatory liabilities

274

Other long-term liabilities

Long-term liabilities associated with assets held for sale

1,148

Total liabilities associated with assets held for sale

1,360

Sale of LIL Equity Interest

On June 4, 2024, Emera completed the sale of its

31.1

per cent indirect minority equity interest in the LIL

for a total transaction value of $

1.2

billion, including cash proceeds of $

957

million and $

235

million for

assuming Emera’s contractual obligation to fund the

remaining initial capital investment, which represents

additional LIL equity interest for the acquirer.

Cash proceeds from the sale in the amount of $

million is

held in escrow pending finalization of certain agreements

with the LIL general partner. The

escrow

proceeds receivable is held at FV and included in the gain

on sale, after transaction costs. As of

December 31, 2024, the estimated FV of the escrow proceeds

receivable is $

million. In Q2 2024, a

gain on sale, after transaction costs, of $

182

million, ($

107

million, after tax and transaction costs), was

recognized in “Other Income, net” on the Consolidated

Statements of Income and included in the Other

segment. In Q4 2024, Emera recognized a $

million tax benefit due to the reversal of a prior year

valuation allowance related to loss carryforwards applied against

a portion of the taxable capital gain on

the sale of LIL. This tax benefit was recorded in “Income Tax

(Recovery) Expense” on the Consolidated

Statements of Income in Q4 2024 and included in the

Other segment.

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, 2024

Operating revenues from

external customers (1)

3,451

1,855

1,595

566

(267)

7,200

Inter-segment revenues

(1)

(42)

Total operating revenues

3,460

1,855

1,609

566

(248)

(42)

7,200

Regulated fuel for generation

and purchased power

852

859

295

(14)

1,992

Regulated cost of natural gas

396

OM&G

779

408

454

143

154

(20)

1,918

Provincial, state and municipal

taxes

273

103

427

Depreciation and amortization

622

282

182

1,162

Impairment charges

214

225

Income from equity

investments

Other income, net

203

Interest expense, net

(2)

265

168

151

367

973

Income tax expense

(recovery)

(41)

(302)

(159)

NCI in subsidiaries

Preferred stock dividends

Net income (loss) attributable

to common shareholders

641

232

259

(686)

494

Capital expenditures

1,942

481

619

3,127

As at December 31, 2024

Total assets

24,375

7,609

8,439

1,444

1,810

(726)

42,951

Investments subject to

significant influence

475

124

654

Goodwill

5,035

823

5,858

(1) All significant inter-company balances and transactions

have been eliminated on consolidation except

for certain transactions

between non-regulated and regulated entities. Management

believes elimination of these transactions would

understate PP&E,

OM&G, or regulated fuel for generation and purchased

power. Inter-company transactions that have not been eliminated

are

measured at the amount of consideration established

and agreed to by the related parties. Eliminated

transactions are included in

determining reportable segments.

(2) Segment net income is reported on a basis

that includes internally allocated financing

costs of $

million for the year ended

December 31, 2024, between the Gas Utilities

and Infrastructure and Other segments.

Florida

Canadian

Gas Utilities

Other

Inter-

Electric

and

Electric

Segment

millions of dollars

Utility

Utilities

Infrastructure

Utilities

Other

Eliminations

Total

For the year ended December 31, 2023

Operating revenues from

external customers

(1)

3,548

1,671

1,510

526

308

7,563

Inter-segment revenues

(1)

(53)

Total operating revenues

3,556

1,671

1,524

526

339

(53)

7,563

Regulated fuel for generation

and purchased power

920

699

275

(13)

1,881

Regulated cost of natural gas

527

OM&G

830

384

405

130

151

(21)

1,879

Provincial, state and municipal

taxes

289

433

Depreciation and amortization

571

276

126

1,049

Income from equity

investments

109

146

Other income, net

158

Interest expense, net

(2)

271

170

129

332

925

Income tax expense (recovery)

117

(9)

(44)

128

NCI in subsidiaries

Preferred stock dividends

Net income (loss) attributable

to common shareholders

627

247

214

(147)

978

Capital expenditures

1,736

450

664

2,921

As at December 31, 2023

Total assets

21,119

8,634

7,735

1,311

1,938

(1,257)

39,480

Investments subject to

significant influence

1,236

118

1,402

Goodwill

4,628

1,240

5,871

(1) All significant inter-company balances and transactions

have been eliminated on consolidation except

for certain transactions

between non-regulated and regulated entities. Management

believes elimination of these transactions would

understate PP&E,

OM&G, or regulated fuel for generation and purchased

power. Inter-company transactions that have not been eliminated

are

measured at the amount of consideration established

and agreed to by the related parties. Eliminated

transactions are included in

determining reportable segments.

(2) Segment net income is reported on a basis

that includes internally allocated financing

costs of $

million for the year ended

December 31, 2023, between the Florida Electric

Utility, Gas Utilities and Infrastructure and Other segments.

Geographical Information

Revenues (based on country of origin of the product or service sold)

For the

Year ended December 31

millions of dollars

2024

2023

United States

4,712

5,310

Canada

1,922

1,727

Barbados

427

389

The Bahamas

139

137

7,200

7,563

PP&E:

As at

December 31

millions of dollars

2024

2023

United States

(1)

20,084

18,588

Canada

5,068

4,878

Barbados

645

576

The Bahamas

371

334

26,168

24,376

(1) On August 5, 2024, Emera announced an agreement to sell

NMGC. As at December 31, 2024, NMGC's assets

and liabilities were classified as held

for sale and excluded from the table above. For further

details on the pending transaction, refer to note 4.

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, 2024

Regulated Revenue

Residential

2,063

997

203

712

3,975

Commercial

939

499

300

496

2,234

Industrial

223

276

(14)

607

Other electric

372

420

Regulatory deferrals

(157)

(142)

Other (1)

224

(9)

290

Finance income (2)(3)

Regulated revenue

3,460

1,855

566

1,589

(23)

7,447

Non-Regulated Revenue

Marketing and trading margin (4)

Other non-regulated operating

revenue

(24)

Mark-to-market (3)

(357)

(352)

Non-regulated revenue

(248)

(19)

(247)

Total operating revenues

3,460

1,855

566

1,609

(248)

(42)

7,200

For the year ended December 31, 2023

Regulated Revenue

Residential

2,307

910

183

724

4,124

Commercial

1,083

463

285

425

2,256

Industrial

274

219

(13)

606

Other electric

395

443

Regulatory deferrals

(522)

(510)

Other (1)

199

(8)

254

Finance income (2)(3)

Regulated revenue

3,556

1,671

526

1,503

(21)

7,235

Non-Regulated

Marketing and trading margin (4)

Other non-regulated operating

revenue

(23)

Mark-to-market (3)

216

(9)

207

Non-regulated revenue

339

(32)

328

Total operating revenues

3,556

1,671

526

1,524

339

(53)

7,563

(1) Other includes rental revenues, which do not

represent revenue from contracts with customers.

(2) Revenue related to Brunswick Pipeline's service agreement

with Repsol Energy Canada.

(3) Revenue which does not represent revenues

from contracts with customers.

(4) Includes gains (losses) on settlement of energy

related derivatives, which do not represent

revenue from contracts with

customers.

Remaining Performance Obligations:

Remaining performance obligations primarily represent

gas transportation contracts, lighting contracts,

and long-term steam supply arrangements with fixed contract

terms. As of December 31, 2024, the

aggregate amount of the transaction price allocated to

remaining performance obligations was $

495

million (2023 – $

488

million), including $

million related to NMGC. This amount includes

135

million of

future performance obligations related to a gas transportation

contract between SeaCoast and PGS

through

2040

. This amount excludes contracts with an original

expected length of one year or less and

variable amounts for which Emera recognizes revenue at the

amount to which it has the right to invoice

for services performed. Emera expects to recognize revenue for

the remaining performance obligations

through

2044

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

2024 (1)

2023

Regulatory assets

Deferred income tax regulatory assets

1,227

1,233

TEC capital cost recovery for early retired assets

737

671

Storm cost recovery clauses

613

Pension and post-retirement medical plan

395

364

TEC capital cost recovery for retired Polk Unit 1 components

205

Deferrals related to derivative instruments

Cost recovery clauses

151

Environmental remediations

Stranded cost recovery

NSPI FAM

395

Other

(2)

119

100

3,427

3,105

Current

595

339

Long-term

2,832

2,766

Total

regulatory assets

3,427

3,105

Regulatory liabilities

Deferred income tax regulatory liabilities

828

830

Accumulated reserve – COR

733

849

Cost recovery clauses

121

NSPI FAM

Deferrals related to derivative instruments

BLPC Self-insurance fund ("SIF") (note 33)

Other

(2)

1,880

1,772

Current

262

168

Long-term

1,618

1,604

Total

regulatory liabilities

1,880

1,772

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

agreement to sell NMGC. As at December

31, 2024, NMGC's assets and liabilities

were classified as held for sale and excluded from

the table above.

For further details on the pending transaction, refer

to note 4.

(2) Comprised of regulatory assets and liabilities

that are not individually significant.

Deferred Income Tax

Regulatory Assets and Liabilities

the extent deferred income taxes are expected to be recovered

from or returned to customers in future

years, a regulatory asset or liability is recognized as appropriate

TEC Capital Cost Recovery for Early Retired Assets

Represents the remaining net book value of Big Bend Power

Station Units 1 through 3 and smart meter

assets that were early retired. The balance earns a rate of return

as permitted by the FPSC and is

recovered as a separate line item on customer bills for

a period of

years, beginning in January 2022.

Storm Cost Recovery Clauses

TEC and PGS Storm Reserve:

The storm reserve is for hurricanes and other named storms

that cause significant damage to TEC and

PGS systems. As allowed by the FPSC, if charges to the

storm reserve exceed the storm reserve liability,

the excess is to be carried as a regulatory asset. TEC

and PGS can petition the FPSC to seek recovery

of restoration costs over a 12-month period or longer,

as determined by the FPSC, as well as replenish

the reserve.

NSPI Storm Rider:

NSPI has a UARB approved storm rider for each of 2023,

2024 and 2025, which gives NSPI the ability to

apply to the UARB for recovery of costs if major storm

restoration expenses exceed approximately $

million in a given year. The

storm rider was effective as of the General Rate

Application (“GRA”) decision

date. The application for deferral and recovery of the storm rider

is made in the year following the year of

the incurred cost, with recovery beginning in the year

after the application.

GBPC Storm Restoration:

This asset includes storm restoration costs incurred by

GBPC related to Hurricane Dorian in 2020 and

Hurricane Matthew in 2016.

Pension and Post-Retirement Medical Plan

This asset is primarily related to the deferred costs of pension and

post-retirement benefits at TEC, PGS

and, in 2023, NMGC. Deferred costs of postretirement

benefits that are included in expense are

recognized as cost of service for rate-making purposes

as permitted by the FPSC and New Mexico Public

Regulation Commission (“NMPRC”), as applicable and

amortized over the remaining service life of plan

participants.

TEC Capital Cost Recovery for Retired Polk Unit 1

Components

This regulatory asset relates to the remaining net book value

of certain components of Polk Unit 1 that

were early retired on December 31, 2024. The balance earns a

rate of return as permitted by the FPSC

and will be recovered through base rates over an

-year recovery period beginning on January 1, 2025.

Deferrals Related to Derivative Instruments

This asset is primarily related to NSPI deferring changes in FV

of derivatives that are documented as

economic hedges or that do not qualify for NPNS exemption,

as a regulatory asset or liability as approved

by the UARB. The realized gain or loss is recognized

when the hedged item settles in regulated fuel for

generation and purchased power,

other income, inventory,

or OM&G, depending on the nature of the item

being economically hedged.

Cost Recovery Clauses

These assets and liabilities are clauses and riders related to

TEC, PGS and, in 2023, NMGC.

They are

recovered or refunded through cost-recovery mechanisms

approved by the FPSC or NMPRC, as

applicable, on a dollar-for-dollar basis in a subsequent

period.

Environmental Remediations

This asset is primarily related to PGS costs associated with environmental

remediation at Manufactured

Gas Plant sites. The balance is included in rate base, partially

offsetting the related liability,

and earns a

rate of return as permitted by the FPSC. The timing of recovery

is based on a settlement agreement

approved by the FPSC.

Stranded Cost Recovery

Due to decommissioning of a GBPC steam turbine in 2012,

the GBPA approved

recovery of a $

million

USD stranded cost through electricity rates; it is included in

rate base and expected to be included in

rates in future years.

NSPI FAM

NSPI has a FAM, approved

by the UARB, allowing NSPI to recover fluctuating fuel

and certain fuel-

related costs from customers through regularly scheduled

fuel rate adjustments. Differences between

prudently incurred fuel costs and amounts recovered from customers

through electricity rates in a year

are deferred to a FAM regulatory

asset or liability and recovered from or returned to

customers in

subsequent periods.

Accumulated Reserve – COR

This regulatory asset or liability represents the non-ARO

COR reserve in TEC, PGS, NSPI and in 2023,

NMGC. AROs represent the FV of estimated cash flows

associated with the Company’s legal obligation to

retire its PP&E.

Non-ARO COR represent estimated funds received

from customers through depreciation

rates to cover future COR of PP&E value upon retirement

that are not legally required. This reduces rate

base for ratemaking purposes. This liability is reduced

as COR are incurred and increased as

depreciation is recorded for existing assets and as new

assets are put into service.

Regulatory Environments and Updates

Florida Electric Utility

TEC is regulated by the FPSC and is also subject to regulation

by the Federal Energy Regulatory

Commission. The FPSC sets rates at a level that allows

utilities such as TEC to collect total revenues or

revenue requirements equal to their cost of providing service,

plus an appropriate return on invested

capital. Base rates are determined in FPSC rate setting

hearings which can occur at the initiative of TEC,

the FPSC or other interested parties.

TEC’s approved regulated return on equity (“ROE”)

range for 2024 and 2023 was

9.25

per cent to

11.25

per cent based on an allowed equity capital structure of

per cent. An ROE of

10.20

per cent (2023 –

10.20

per cent) is used for the calculation of the return

on investments for clauses.

Base Rates:

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

new base rates. On December 3, 2024, the

FPSC rendered a decision which includes annual base

rate increases of $

185

million USD in 2025 and

adjustments of $

million USD and $

million USD in 2026 and 2027, respectively.

The allowed equity in

the capital structure will continue to be

per cent from investor sources of capital and the allowed

regulatory ROE range is

9.50

per cent to

11.50

per cent with a

10.50

per cent midpoint. On February 3,

2025, the FPSC issued the final order approving the decision,

effective January 1, 2025. On February 18,

2025, a motion for reconsideration on certain aspects of the

rate case order was filed with the FPSC.

On August 16, 2023, TEC filed a petition to implement the

2024 Generation Base Rate Adjustment

provisions pursuant to the 2021 rate case settlement agreement.

Inclusive of TEC’s ROE adjustment, the

increase of $

million USD was approved by the FPSC on November

17, 2023.

Fuel Recovery and Other Cost Recovery Clauses:

TEC has a fuel recovery clause approved by the FPSC,

allowing the opportunity to recover fluctuating

fuel expenses from customers through annual fuel rate

adjustments. The FPSC annually approves cost-

recovery rates for purchased power,

capacity, environmental

and conservation costs, including a return

on capital invested. Differences between prudently

incurred fuel costs and the cost-recovery rates

and

amounts recovered from customers through electricity

rates in a year are deferred to a regulatory asset or

liability and recovered from or returned to customers

in subsequent periods.

On April 2, 2024, TEC requested a mid-course adjustment

to its fuel and capacity charges, reflecting a

138

million USD reduction over

12 months

, from June 2024 through May 2025. The requested

reduction

was due to a decrease in actual and projected 2024 natural

gas prices since TEC submitted its projected

2024 costs in the fall of 2023. On May 7, 2024, the FPSC

approved the mid-course adjustment.

On January 23, 2023, TEC requested an adjustment

to its fuel charges to recover the 2022 fuel under-

recovery of $

518

million USD over a period of

21 months

. The request also included an adjustment to

2023 projected fuel costs to reflect the reduction in natural gas

prices since September 2022 for a

projected reduction of $

170

million USD for the balance of 2023. The changes were

approved by the

FPSC on March 7, 2023, and were effective

beginning on April 1, 2023.

Storm Reserve:

September 26, 2024, Hurricane Helene passed 100 miles west

of Tampa

and made landfall

approximately 200 miles north of Tampa,

in Taylor

County, as a Category

4 hurricane. TEC’s service

territory was impacted by the tropical storm force winds

and storm surge which resulted in a peak number

of customers out of 100,000. As of December 31, 2024, TEC

deferred $

million USD to the storm

reserve for future recovery.

On October 9, 2024, Hurricane Milton made landfall approximately

50 miles south of Tampa,

near

Sarasota, and was the worst weather event to impact the

area in over 100 years. The Category 3

hurricane had a significant impact on TEC’s service

territory which resulted in a peak number of

customers out of 600,000. As of December 31, 2024, TEC deferred

340

million USD to the storm

reserve for future recovery

As at December 31, 2024, total restoration costs charged

to the storm reserve account have exceeded

the storm reserve balance, and therefore $

377

million USD has been deferred as a regulatory asset

for

future recovery. On February

4, 2025, the FPSC approved TEC’s petition, filed

on December 27, 2024,

for the recovery of $

466

million USD for costs associated with Hurricane Idalia, Hurricane

Debby,

Hurricane Helene and Hurricane Milton and the associated

interest which will replenish the storm reserve

over an 18-month recovery period beginning March 2025.

The amount of cost-recovery is subject to a

true-up mechanism with the FPSC.

In September 2022, TEC was impacted by Hurricane Ian, with

119

million USD of restoration costs

charged against TEC’s FPSC approved storm reserve.

On January 23, 2023, TEC petitioned the FPSC

for recovery of the storm reserve regulatory asset and the replenishment

of the balance in the storm

reserve to the approved storm reserve level of $

million USD, for a total of $

131

million USD. The storm

cost recovery surcharge was approved by the FPSC on March

7, 2023, and TEC began applying the

surcharge in April 2023. Subsequently,

on November 9, 2023, the FPSC approved TEC’s

petition, filed on

August 16, 2023, to update the total storm cost collection

to $

134

million USD. The remaining balance of

million USD as of December 31, 2023, was collected over

12 months in 2024.

Storm Protection Cost Recovery Clause and Settlement

Agreement:

The Storm Protection Plan Cost Recovery Clause provides

a process for Florida investor-owned utilities,

including TEC, to recover transmission and distribution

storm hardening costs for incremental activities

not already included in base rates. Differences between

prudently incurred clause-recoverable costs and

amounts recovered from customers through electricity

rates in a year are deferred and recovered from or

returned to customers in a subsequent year.

The current approved plan addressed the years 2023,

2024

and 2025 and was approved by the FPSC in October,

2022.

Canadian Electric Utilities

NSPI

NSPI is a public utility as defined in the Public Utilities

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

subject to regulation under the Public Utilities Act by the UARB.

The Public Utilities Act gives the UARB

supervisory powers over NSPI’s operations and

expenditures. Electricity rates for NSPI’s customers

are

also subject to UARB approval. NSPI is not subject to

a general annual rate review process, but rather

participates in hearings held from time to time at NSPI’s

or the UARB’s request.

NSPI is regulated under a cost-of-service model, with rates

set to recover prudently incurred costs of

providing electricity service to customers and provide a

reasonable return to investors. NSPI’s approved

regulated ROE range for 2024 and 2023 was

8.75

per cent to

9.25

per cent based on an actual five

quarter average regulated common equity component

of up to

per cent of approved rate base.

GRA:

On February 2, 2023, the UARB approved the GRA settlement

agreement between NSPI, key customer

representatives and participating interest groups. This resulted

in average customer rate increases of

6.9

per cent effective on February 2, 2023, and further

average increases of

6.5

per cent on January 1, 2024,

with any under or over-recovery of fuel costs addressed through

the UARB’s established FAM

process. It

also established a storm rider and a demand-side management

rider. On March 27,

2023, the UARB

issued a final order approving the electricity rates effective

on February 2, 2023.

Fuel Recovery:

On April 17, 2024, the UARB approved the sale of $

117

million of the FAM regulatory

asset to Invest

Nova Scotia, a provincial Crown corporation. On April

30, 2024, the transaction closed and the $

117

million was remitted to NSPI, which resulted in a corresponding

decrease of the FAM regulatory

asset.

NSPI is collecting the amortization and financing costs

related to the $

117

million from customers on

behalf of Invest Nova Scotia over a

-year period, which began in Q2 2024, and is

remitting those

amounts to Invest Nova Scotia quarterly.

Federal Loan Guarantee (“FLG”):

On September 24, 2024, the Government of Canada finalized

an agreement with NSPI, NSPML and the

Province of Nova Scotia (the “Province”) on terms and

conditions for a FLG of $

500

million in debt to be

issued by NSPML to help Nova Scotia customers manage

unrecovered costs of the replacement energy

that was required during the several years of delay in the

Muskrat Falls hydroelectricity project. On

September 25, 2024, NSPI and NSPML filed applications

with the UARB related to the FLG. On

November 29, 2024, the UARB approved NSPML’s

application to issue the debt, transfer the proceeds

NSPI as a refund of a portion of previous NSPML assessment

payments, and to increase its annual

assessment charge to NSPI to recover the refund and

related financing costs over a

-year period. On

December 16, 2024, the net proceeds of the NSPML debt

issuance were transferred to NSPI and applied

against the FAM regulatory

asset balance. On February 18, 2025, the UARB approved

NSPI's application

to increase 2025 fuel rates to service the incremental

NSPML debt.

Storm Rider:

On December 2, 2024, the UARB approved the recovery

of $

million of major storm restoration and

incremental financing costs deferred to NSPI’s storm

rider in 2023 to be recovered over a

-month

period beginning on January 1, 2025.

Hurricane Fiona:

On June 27, 2024, the UARB approved the deferred recognition

of $

million in incremental operating

costs incurred during the Hurricane Fiona storm restoration

efforts in September 2022. Following UARB

approval, the $

million was reclassified to “Regulatory assets”

from “Other long-term assets”. The

UARB also directed NSPI to reclassify $

million of undepreciated costs related to assets retired

because of Hurricane Fiona to “Regulatory assets” from “PP&E”

on the Consolidated Balance Sheets.

NSPI began amortizing both of these regulatory assets

over a

-year period beginning July 1, 2024.

Nova Scotia Cap-and-Trade

(“Cap-and-Trade”)

Program:

On December 31, 2022, the FAM

included a cumulative $

166

million in fuel costs related to the accrued

purchase of emissions credits and $

million related to credits purchased from provincial auctions.

March 16, 2023, the Province provided NSPI with emissions

allowances sufficient to achieve compliance

for the 2019 through 2022 period. As such, compliance costs

accrued of $

166

million were reversed in Q1

2023. The credits NSPI purchased from provincial auctions

in the amount of $

million were not refunded

and no further costs were incurred to achieve compliance

with the Cap-and-Trade Program.

Extra Large Industrial Active Demand Tariff:

On July 5, 2023, NSPI received approval from the UARB to

change the methodology in which fuel cost

recovery from an industrial customer is calculated. Due to significant

volatility in commodity prices in

2022, the previous methodology did not result in a reasonable

determination of the fuel cost to serve this

customer. The change in methodology,

effective January 1, 2022, results in a shifting

of fuel costs from

this industrial customer to the FAM.

This adjustment was recorded in Q2 2023 resulting

in a $

million

increase to the FAM regulatory

asset and an offsetting decrease to unbilled revenue

within Receivables

and other current assets. This adjustment had minimal

impact on earnings.

NSPML

Equity earnings from the Maritime Link are dependent

on the approved ROE and operational

performance of NSPML. NSPML’s

approved regulated ROE range is

8.75

per cent to

9.25

per cent,

based on an actual five-quarter average regulated common

equity component of up to

per cent.

Newfoundland and Labrador Hydro’s (“NLH”) Nova

Scotia Block (“NS Block”) delivery obligations

commenced in 2021 and delivery will continue over the next

35 years

pursuant to the agreements.

On September 24, 2024, the Government of Canada finalized

an agreement with NSPI, NSPML, and the

Province on terms and conditions for a FLG of $

500

million in debt to be issued by NSPML. For further

information, refer to the NSPI section above.

On November 29, 2024, NSPML received approval from the

UARB to collect up to $

197

million in 2025

from NSPI; which includes $

158

million for the recovery of costs associated with the Maritime

Link, and

million associated with the additional FLG debt and financing costs

noted in the NSPI section above.

Payments from NSPI are subject to a holdback of up to $

million per month. There was

holdback

recorded for the year ended December 31, 2024.

On December 21, 2023, NSPML received approval from the

UARB to collect up to $

164

million in 2024

from NSPI for the recovery of costs associated with the

Maritime Link subject to a holdback of $

million

per month.

On October 4, 2023 and January 31, 2024, the UARB issued

decisions providing clarification on

remaining aspects of the Maritime Link holdback mechanism

primarily relating to release of past and

future holdback amounts and requirements to end the holdback

mechanism. In these decisions, the

UARB agreed with the Company’s submission that

million ($

million related to 2022 and $

million

related to 2023) of the previously recorded holdback remain

credited to NSPI’s FAM,

with the remainder

released to NSPML and recorded in Emera’s “Income

from equity investments”. The UARB also

confirmed that NSPML can apply for termination of the

holdback mechanism upon

per cent of NS

Block deliveries being achieved for 12 consecutive months (subject

to potential relief for planned outages

or exceptional circumstances) and the net outstanding

balance of previously underdelivered NS Block

energy is less than

per cent of the contracted annual amount. In addition,

the UARB increased the

monthly holdback amount from $

million to $

million beginning December 1, 2023.

Gas Utilities and Infrastructure

PGS

PGS is regulated by the FPSC. The FPSC sets rates at

a level that allows utilities such as PGS to collect

total revenues or revenue requirements equal to their

cost of providing service, plus an appropriate return

on invested capital.

PGS’s approved ROE range for 2024 and 2023

was

9.15

per cent to

11.15

per cent with a

10.15

per cent

midpoint, based on an allowed equity capital structure

54.7

per cent.

Base Rates:

On April 4, 2023, PGS filed a rate case with the FPSC

and a hearing for the matter was held in

September 2023. On November 9, 2023, the FPSC approved

a $

118

million USD increase to base

revenues which includes $

million USD transferred from the cast iron and bare

steel replacement rider,

for a net incremental increase to base revenues of $

107

million USD. This reflects a

10.15

per cent

midpoint ROE with an allowed equity capital structure of

54.7

per cent. A final order was issued on

December 27, 2023, with the new rates effective January

2024.

Fuel Recovery:

PGS recovers the costs it pays for gas supply and

interstate transportation for system supply through its

Purchased Gas Adjustment Clause (“PGAC”). This clause is designed

to recover actual costs incurred by

PGS for purchased gas, gas storage services, interstate pipeline

capacity, and

other related items

associated with the purchase, distribution, and sale of

natural gas to its customers.

These charges may

be adjusted monthly based on a cap approved annually

by the FPSC.

Recovery of Energy Conservation and Pipeline Replacement

Programs:

The FPSC annually approves a conservation charge that

is intended to permit PGS to recover prudently

incurred expenditures in developing and implementing

cost effective energy conservation programs

which

are required by Florida law and approved and monitored

by the FPSC. PGS also has a Cast Iron/Bare

Steel Pipe Replacement clause to recover the cost of accelerating

the replacement of cast iron and bare

steel distribution lines in the PGS system. In February 2017,

the FPSC approved expansion of the Cast

Iron/Bare Steel clause to allow recovery of accelerated

replacement of certain obsolete plastic pipe. The

majority of cast iron and bare steel pipe has been removed

from its system, with replacement of obsolete

plastic pipe continuing until 2028 under the rider.

NMGC

NMGC is subject to regulation by the NMPRC. The NMPRC

sets rates at a level that allows NMGC to

collect total revenues equal to its cost of providing service,

plus an appropriate return on invested capital.

NMGC’s approved ROE for 2024 and 2023

was

9.375

per cent on an allowed equity capital structure of

per cent.

Base Rates:

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

the NMPRC for new base rates.

On March 1, 2024,

NMGC filed with the NMPRC a settlement with the support

of all parties in the case for an increase of $

million USD in annual base revenues and maintaining

NMGC’s ROE at

9.375

per cent. The rates reflect

the recovery of increased operating costs and capital investments

in pipeline projects and related

infrastructure, as well as a new customer information and

billing system. NMGC also agreed to withdraw,

and to not reassert in a future rate case application,

its request for a regulatory asset for costs associated

with its 2022 application for a certificate of public convenience

and necessity for a liquefied natural gas

storage facility in New Mexico. The NMPRC approved

the rate case settlement on July 25, 2024. New

rates became effective October 1, 2024.

Fuel Recovery:

NMGC recovers gas supply costs through a PGAC. This

clause recovers actual costs for purchased gas,

gas storage services, interstate pipeline capacity,

and other related items associated with the purchase,

transmission, distribution, and sale of natural gas to its

customers. On a monthly basis, NMGC can adjust

charges based on the next month’s expected cost

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

recovery. The NMPRC

requires that NMGC annually file a reconciliation

of the PGAC period costs and

recoveries. NMGC must file a PGAC Continuation Filing

with the NMPRC every four years to establish

that the continued use of the PGAC is reasonable and

necessary. NMGC

received approval of its PGAC

Continuation in December 2024, for the four-year period

ending December 2028.

Brunswick Pipeline

Brunswick Pipeline is a

145

-kilometre pipeline delivering natural gas from the Saint

John LNG import

terminal near Saint John, New Brunswick to markets in

the northeastern US. Brunswick Pipeline entered

into a

-year firm service agreement commencing in July

2009 with Repsol Energy Canada. The

agreement provides for a predetermined toll increase

in the fifth and fifteenth year of the contract. The

pipeline is considered a Group II pipeline regulated by

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

Gas Transportation Tariff

is filed by Brunswick Pipeline in compliance with the

requirements of the CER

Act and sets forth the terms and conditions of the transportation

rendered by Brunswick Pipeline.

Other Electric Utilities

BLPC

BLPC is regulated by the Fair Trading

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

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

with rates set to recover prudently incurred

costs of providing electricity service to customers plus

an appropriate return on capital invested. BLPC’s

approved regulated return on rate base was

per cent for 2024 and 2023.

Licenses:

BLPC currently operates pursuant to a single integrated license

to generate, transmit and distribute

electricity on the island of Barbados until 2028. In 2019, the Government

of Barbados passed legislation

requiring multiple licenses for the supply of electricity.

In 2021, BLPC reached commercial agreement with

the Government of Barbados for each of the license types,

subject to the passage of implementing

legislation. The timing of the final enactment is unknown at

this time, but BLPC will work towards the

implementation of the licenses once enacted.

Base Rates:

In 2021, BLPC submitted a general rate review application

to the FTC. In September 2022, the FTC

granted BLPC interim rate relief, allowing an increase in base rates

of approximately $

million USD per

month. On February 15, 2023, the FTC issued a decision

on the application which included the following

significant items: an allowed regulatory ROE of

11.75

per cent, an equity capital structure of

per cent,

a directive to update the major components of rate base

to September 16, 2022, and a directive to

establish regulatory liabilities totalling approximately $

million USD. On March 7, 2023, BLPC filed a

Motion for Review and Variation

(the “Motion”) and applied for a stay of the FTC’s

decision, which was

subsequently granted. On November 20, 2023, the FTC

issued their decision dismissing the Motion.

Interim rates continue to be in effect through to

a date to be determined in a final decision and order.

On December 1, 2023, BLPC appealed certain aspects

of the FTC’s February 15 and November 20,

2023, decisions to the Supreme Court of Barbados in the

High Court of Justice (the “Court”) and

requested that they be stayed. On December 11,

2023, the Court granted the stay.

BLPC’s position is

that the FTC made errors of law and jurisdiction in their

decisions and believes the success of the appeal

is probable, and as a result, the adjustments to BLPC’s

final rates and rate base, including any

adjustments to regulatory assets and liabilities, have not been

recorded at this time. The appeal is

currently scheduled to be heard in 2025.

Fuel Recovery:

BLPC’s fuel costs flow through a fuel pass-through

mechanism which provides opportunity to recover

all

prudently incurred fuel costs from customers in a timely

manner. The calculation of the fuel

charge is

adjusted on a monthly basis and reported to the FTC for

approval.

Clean Energy Transition

Rider (“CETR”):

On May 31, 2023, the FTC approved BLPC’s

application to establish an alternative cost recovery

mechanism to recover prudently incurred costs associated

with its CETR (the “Decision”). The

mechanism is intended to facilitate the timely recovery between

rate cases of costs associated with

approved renewable energy assets. BLPC will be required

to submit an individual application for the

recovery of costs of each asset through the cost recovery

mechanism, meeting the minimum criteria as

set out in the Decision. On October 5, 2023, BLPC applied

to the FTC to recover the costs of a battery

storage system through the CETR. On May 6, 2024, the

FTC approved the recovery of a

MW battery

storage system through the CETR.

Barbados Domestic Tax

Rate Change:

On May 24, 2024, the Government of Barbados signed

the Income Tax

(Amendment and Validation)

Act

into law. The legislation, effective

January 1, 2024, implemented a corporate income

tax rate of

per

cent, requiring BLPC to remeasure its deferred income

tax liabilities. On July 18, 2024, BLPC requested

the deferred recovery of the $

million USD remeasurement. BLPC is seeking amortization

of the costs

over a period to be approved by the FTC during a future

rate setting process.

GBPC

GBPC is regulated by the GBPA.

The GBPA

has granted GBPC a licensed, regulated and exclusive

franchise to produce, transmit and distribute electricity

on the island until 2054. Rates are set to recover

prudently incurred costs of providing electricity service

to customers plus an appropriate return on rate

base. GBPC’s approved regulated return on rate base

was

8.52

per cent for 2024 (2023 –

8.32

per cent).

Electricity Act, 2024:

On June 1, 2024, the Electricity Act, 2024 took effect.

The legislation purports to remove the jurisdiction of

the GBPA over GBPC

and to have the Utilities Regulation and Competition

Authority, another

Bahamian

regulator, regulate GBPC.

Base Rates:

There is a fuel pass-through mechanism and tariff review

policy with new rates submitted every three

years. On August 1, 2024, as required by the GBPA

Operating Protocol and Regulatory Framework

Agreement, GBPC filed a rate plan proposal and is awaiting

regulatory review.

Fuel Recovery:

GBPC’s fuel costs flow through a fuel pass-through

mechanism which provides the opportunity to recover

all prudently incurred fuel costs from customers in a timely

manner. In 2023 and 2024,

the fuel pass

through charge was adjusted monthly,

in-line with actual fuel costs.

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

2024

2023

2024

2023

2024

NSPML

475

489

100.0

M&NP

(1)

124

118

12.9

Lucelec

(1)

19.5

LIL

(2)

747

Bear Swamp

(3)

50.0

654

1,402

146

(1) Emera has significant influence over the operating

and financial decisions of these companies through

Board representation

and therefore, records its investment in these

entities using the equity method.

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

of its equity interest in the LIL. For further

details, refer to note 4.

(3) The investment balance in Bear Swamp is

in a credit position primarily as a result

of a $

179

million distribution received in 2015.

Bear Swamp's credit investment balance of $

million (2023 – $

million) is recorded in Other long-term liabilities

on the

Consolidated Balance Sheets.

Equity investments include a $

million difference between the cost and the

underlying FV of the

investees' assets as at the date of acquisition. The excess

is attributable to goodwill.

Emera accounts for its variable interest investment in

NSPML as an equity investment (note 33).

NSPML's consolidated summarized balance sheets are illustrated

as follows:

As at

December 31

millions of dollars

2024

2023

Balance Sheets

Current assets

PP&E

1,425

1,473

Regulatory assets

(1)

778

272

Non-current assets

Total

assets

2,267

1,795

Current liabilities

Long-term debt

(2)

1,570

1,109

Non-current liabilities

167

149

Equity

475

489

Total

liabilities and equity

2,267

1,795

(1) On November 29, 2024, the UARB approved

the creation of a $

500

million regulatory asset for debt issued as a

result of the

FLG. For further details, refer to note 7.

(2) On December 16, 2024, NSPML issued a

500

million bond under the FLG. For further details

refer to note 7.

9. OTHER INCOME, NET

For the

Year ended December 31

millions of dollars

2024

2023

Gain on sale of LIL, net of transaction costs

(1)

182

AFUDC

Pension non-current service cost recovery

Interest income

Transaction costs related to the pending sale of NMGC

(1)

(25)

Charges related to wind-down costs and certain asset impairments (2)

(29)

FX (losses) gains

(58)

Other

203

158

(1) For more information related to the gain

on sale, after transaction costs, of Emera's indirect

minority interest in the LIL and the

pending sale of NMGC, refer to note 4.

(2) Primarily related to the wind-down of Block

Energy LLC

10. INTEREST EXPENSE, NET

Interest expense, net consisted of the following:

For the

Year ended December 31

millions of dollars

2024

2023

Interest on debt

1,004

954

Allowance for borrowed funds used during construction

(23)

(16)

Other

(8)

(13)

973

925

11. INCOME TAXES

The income tax provision, for the years ended December

31, differs from that computed using the

enacted combined Canadian federal and provincial statutory

income tax rate for the following reasons:

millions of dollars

2024

2023

Income before provision for income taxes

409

1,173

Statutory income tax rate

29.0%

Income taxes, at statutory income tax rate

119

340

Deferred income taxes on regulated income recorded as regulatory assets and

regulatory liabilities

(90)

(72)

Interest and financing expenses

(58)

Valuation allowance

(58)

Tax

credits

(57)

(53)

Goodwill impairment charge

Amortization of deferred income tax regulatory liabilities

(36)

(33)

Foreign tax rate variance

(31)

(36)

Additional impact from the sale of LIL equity interest

Tax

effect of equity earnings

(14)

(15)

Manufacturing allowance

(9)

(8)

Other

Income tax (recovery) expense

(159)

128

Effective income tax rate

(39%)

11%

Bahamian Domestic Minimum Top

-up Tax

Act (“Domestic Top

-up Tax

Act”):

On November 28, 2024, the Domestic Top

-up Tax

Act was enacted with an effective date of January

2024.The Domestic Top

-up Tax

Act did not have an impact on the Company.

Excessive Interest and Financing Expenses Limitation

(“EIFEL”) Regime:

On June 20, 2024, Bill C-59, an Act to implement certain provisions

of the fall economic statement tabled

in Parliament on November 21, 2023, and certain provisions

of the budget tabled in Parliament on March

28, 2023, was enacted.

Bill C-59 includes the EIFEL regime, which is effective

January 1, 2024. EIFEL

applies to limit a company’s net interest and financing

expense deduction to no more than 30 per cent of

earnings before interest, income taxes, depreciation, and amortization

for tax purposes. Any denied

interest and financing expenses under the EIFEL regime can

be carried forward indefinitely.

During 2024, the Company incurred $

185

million of interest and financing expenses in connection with

specific financing structure. The interest and financing expenses

related to the financing structure as well

as $

million of other interest and financing expenses are expected

to be denied under the EIFEL

regime. It was determined that the Company is more likely

than not to realize the tax benefit of the denied

interest and financing expenses in future periods and therefore

a $

million deferred income tax asset

has been recorded as at December 31, 2024. In Q4 2024, the

Company recognized a $

million tax

benefit related to the denied interest and financing expenses

and the reversal of the related deferred

income tax liability in connection with the financing structure

and its wind-up.

Canadian Global Minimum Tax

Act (“GMTA”):

On June 20, 2024, the GMTA

was enacted with an effective date of January

1, 2024. The GMTA

did not

have an impact on the Company.

Barbados Domestic Tax

Rate Change:

On May 24, 2024, the Government of Barbados signed the

Income Tax

(Amendment and Validation)

Act

into law. The legislation, effective

January 1, 2024, implemented a corporate income tax

rate of

per

cent, requiring BLPC to remeasure its deferred income

tax liabilities.

Barbados Corporation Top

-up Tax

(Amendment) Act (“Top

-up Tax

Act”):

On May 24, 2024, the Top

-up Tax

Act was enacted with an effective date of January

1, 2024. The Top

-up

Tax

Act did not have an impact on the Company

United States Inflation Reduction Act (“IRA”):

On August 16, 2022, the IRA was signed into legislation.

The IRA includes numerous tax incentives for

clean energy, such

as the extension and modification of existing investment

and production tax credits for

projects placed in service through 2024, and introduces

new technology-neutral clean energy related tax

credits beginning in 2025. As of December 31, 2024, the

Company has recorded a $

million (December

31, 2023 – $

million) regulatory liability on the Consolidated Balance

Sheets in recognition of its

obligation to pass the incremental tax benefits realized

to customers.

The following table reflects the composition of taxes on

income from continuing operations presented in

the Consolidated Statements of Income for the years ended

December 31:

millions of dollars

2024

2023

Current income taxes

Canada

United States

Deferred income taxes

Canada

(200)

United States

155

128

Adjustments to beginning of the year valuation allowance

Canada

(61)

Investment tax credits

United States

(6)

(29)

Operating loss carryforwards

Canada

(4)

(93)

United States

(76)

(2)

Income tax (recovery) expense

(159)

128

The following table reflects the composition of income

before provision for income taxes presented in the

Consolidated Statements of Income for the years ended

December 31:

millions of dollars

2024

2023

Canada

156

171

United States

203

964

Other

Income before provision for income taxes

409

1,173

The deferred income tax assets and liabilities presented in

the Consolidated Balance Sheets as at

December 31 consisted of the following:

millions of dollars

2024

2023

Deferred income tax assets:

Tax

loss carryforwards

1,118

1,195

Tax

credit carryforwards

534

454

Regulatory liabilities

225

175

Derivative instruments

144

205

Other

462

372

Total

deferred income tax assets before valuation allowance

2,483

2,401

Valuation allowance

(322)

(363)

Total

deferred income tax assets after valuation allowance

2,161

2,038

Deferred income tax liabilities:

PP&E

(3,421)

(3,223)

Regulatory assets

(198)

(196)

Derivative instruments

(105)

(235)

Investments subject to significant influence

(46)

(216)

Other

(330)

(312)

Total

deferred income tax liabilities

(4,100)

(4,182)

Consolidated Balance Sheets presentation:

Long-term deferred income tax assets

392

208

Long-term deferred income tax liabilities

(2,331)

(2,352)

Net deferred income tax liabilities

(1,939)

(2,144)

Considering all evidence regarding the utilization of the Company’s

deferred income tax assets, it has

been determined that Emera is more likely than not to realize

all recorded deferred income tax assets,

except for certain loss carryforwards and unrealized capital

losses on long-term debt and investments. A

valuation allowance of $

322

million has been recorded as at December 31, 2024 (2023

– $

363

million)

related to the loss carryforwards, long-term debt and investments.

During 2024, the Company recognized

a $

million tax benefit primarily due to the utilization of certain

loss carryforwards, which were subject to

a valuation allowance as at December 31, 2023.

The Company intends to indefinitely reinvest earnings

from certain foreign operations. Accordingly,

4.7

billion as at December 31, 2024 (2023 – $

4.7

billion) in cumulative temporary differences for which

deferred taxes might otherwise be required, have not

been recognized. It is impractical to estimate the

amount of income and withholding tax that might be payable

if a reversal of temporary differences

occurred.

Emera’s NOL, capital loss and tax credit carryforwards

and their expiration periods as at December 31,

2024 consisted of the following:

Subject to

Tax

Valuation

Net Tax

Expiration

millions of dollars

Carryforwards

Allowance

Carryforwards

Period

Canada

NOL

2,420

(967)

1,453

2026 - 2044

Capital loss

(55)

Indefinite

Tax Credit

(1)

2028 - 2042

United States

Federal NOL

1,587

(1)

1,586

2036 - Indefinite

State NOL

1,351

(1)

1,350

2026 - Indefinite

Tax credit

533

(3)

530

2025 - 2044

Other

NOL

(23)

2025 - 2031

The following table provides details of the change in unrecognized

tax benefits for the years ended

December 31 as follows:

millions of dollars

2024

2023

Balance, January 1

Increases due to tax positions related to current year

Increases due to tax positions related to a prior year

Decreases due to tax positions related to a prior year

(3)

(2)

Balance, December 31

Unrecognized tax benefits relate to the timing of certain

tax deductions at NSPI and research and

development tax credits primarily at TEC. The total amount

of unrecognized tax benefits as at December

31, 2024 was $

million (2023 – $

million), which would affect the effective

tax rate if recognized. The

total amount of accrued interest with respect to unrecognized tax

benefits was $

million (2023 – $

million) with $

million interest expense recognized in the Consolidated

Statements of Income (2023 – $

million).

penalties have been accrued. The balance of unrecognized

tax benefits could change in the

next 12 months as a result of resolving Canada Revenue

Agency (“CRA”) and Internal Revenue Service

audits. A reasonable estimate of any change cannot be made

at this time.

NSPI and the CRA are currently in a dispute with respect

to the timing of certain tax deductions for

its 2006 through 2010 and 2013 through 2016 taxation

years. The ultimate permissibility of the tax

deductions is not in dispute; rather,

it is the timing of those deductions. The cumulative net

amount in

dispute to date is $

126

million (2023 – $

126

million), including interest. NSPI has prepaid $

million

(2023 – $

million) of the amount in dispute, as required by

CRA.

On November 29, 2019, NSPI filed a Notice of Appeal

with the Tax

Court of Canada with respect to its

dispute of the 2006 through 2010 taxation years. Should

NSPI be successful in defending its position, all

payments including applicable interest will be refunded.

If NSPI is unsuccessful in defending any portion

of its position, the resulting taxes and applicable interest

will be deducted from amounts previously paid,

with the difference, if any,

either owed to, or refunded from, the CRA. The related

tax deductions will be

available in subsequent years.

Should NSPI be similarly reassessed by the CRA for years

not currently in dispute, further payments will

be required; however, the

ultimate permissibility of these deductions would be

similarly not in dispute.

NSPI and its advisors believe that NSPI has reported

its tax position appropriately.

NSPI continues to

assess its options to resolving the dispute; however,

the outcome of the Notice of Appeal process is not

determinable at this time.

Emera files a Canadian federal income tax return, which

includes its Nova Scotia provincial income tax.

Emera’s subsidiaries file Canadian, US, Barbados,

and St. Lucia income tax returns. As at December

31,

2024, the Company’s tax years still open to examination

by taxing authorities include 2006 and

subsequent years.

12. COMMON STOCK

Authorized

: Unlimited number of non-par value common shares.

2024

2023

Issued and outstanding:

millions

of shares

millions of

dollars

millions of

dollars

Balance, January 1

284.12

8,462

269.95

7,762

Issuance of common stock under ATM program

(1)(2)

5.12

261

8.29

397

Issued under the DRIP,

net of discounts

6.10

291

5.26

272

Senior management stock options exercised and Employee Share

Purchase Plan

0.60

0.62

Balance, December 31

295.94

9,042

284.12

8,462

(1) For the year ended December 31, 2023, a

total of

8,287,037

common shares were issued under Emera's ATM program at an

average price of $

48.27

per share for gross proceeds of $

400

million ($

397

million net of after-tax issuance costs).

(2) For the year ended December 31, 2024, a

total of

5,117,273

common shares were issued under Emera's ATM program at an

average price of $

51.52

per share for gross proceeds of $

264

million ($

261

million net of after-tax issuance costs). As at December

31, 2024, an aggregate gross sales limit of $

336

million remained available for issuance under the

ATM program.

As at December 31, 2024, the following common shares

were reserved for issuance:

million (2023 –

million) under the senior management stock option plan,

million (2023 –

million) under the employee

common share purchase plan and

million (2023 –

million) under the DRIP.

The issuance of common shares under the common share compensation

arrangements does not allow

the plans to exceed

per cent of Emera's outstanding common shares. As at

December 31, 2024,

Emera was in compliance with this requirement.

ATM Equity Program

On November 18, 2024, Emera increased the size of

the ATM Program to

allow the Company to issue up

to $

billion of common shares from treasury to the public from

time to time, at the Company's discretion,

at the prevailing market price. The ATM

Program was increased by an amendment dated November 18,

2024 to its prospectus supplement dated November 14, 2023 and

an amendment dated November 13,

2024 to its short form base shelf prospectus dated October 3,

2023.

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)

2024

2023

Numerator

Net income attributable to common shareholders

493.6

977.7

Diluted numerator

493.6

977.7

Denominator

Weighted average shares of common stock outstanding – basic

289.1

273.6

Stock-based compensation

0.1

0.2

Weighted average shares of common stock outstanding – diluted

289.2

273.8

Earnings per common share

Basic

1.71

3.57

Diluted

1.71

3.57

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, 2024

Balance, January 1, 2024

369

(24)

(2)

(52)

305

OCI before

reclassifications

1,027

(139)

890

Amounts reclassified from

AOCI

(2)

Net current period OCI

1,027

(139)

(2)

956

Balance, December 31, 2024

1,396

(163)

1,261

For the year ended December 31, 2023

Balance, January 1, 2023

639

(62)

(2)

(13)

578

OCI before

reclassifications

(270)

(232)

Amounts reclassified from

AOCI

(2)

(39)

(41)

Net current period OCI

(270)

(2)

(39)

(273)

Balance, December 31, 2023

369

(24)

(2)

(52)

305

The reclassifications out of AOCI are as follows:

For the

Year ended December 31

millions of dollars

2024

2023

Affected line item in the Consolidated Financial Statements

Gains on derivatives recognized as cash flow hedges

Interest rate hedge

Interest expense, net

(2)

Net change in unrecognized pension and post-retirement benefit costs

Actuarial losses

Other income, net

Past service (gains) costs

Other income, net

(2)

Amounts reclassified into obligations

Pension and post-retirement benefits

(40)

Total

before tax

(38)

Income tax expense

(1)

Total

net of tax

(39)

Total reclassifications out of AOCI, net of tax, for the period

(41)

15. INVENTORY

As at

December 31

millions of dollars

2024

2023

Materials

453

408

Fuel

328

382

Total

781

790

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

2024

2023

2024

2023

Regulatory deferral:

Commodity swaps and forwards

FX forwards

HFT derivatives:

Power swaps and physical contracts

Natural gas swaps, futures, forwards, physical

contracts

236

319

660

531

270

348

690

567

Other derivatives:

Equity derivatives

FX forwards

Total

gross current derivatives

322

389

773

653

Impact of master netting agreements:

Regulatory deferral

(7)

(3)

(7)

(3)

HFT derivatives

(148)

(146)

(148)

(146)

Total

impact of master netting agreements

(155)

(149)

(155)

(149)

Less: Derivatives classified as held for sale

(1)

Total derivatives

166

240

617

504

Current

(2)

115

174

526

386

Long-term

(2)

118

Total derivatives

166

240

617

504

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

agreement to sell NMGC. As at December

31, 2024, NMGC's assets and liabilities

were classified as held for sale. For further details

on the pending transaction, refer to note 4.

(2) Derivative assets and liabilities are classified

as current or long-term based upon the maturities

of the underlying contracts.

Cash Flow Hedges

On May 26, 2021, a treasury lock was settled for a

gain of $

million that is being amortized through

interest expense over

10 years

as the underlying hedged item settles. As of December 31,

2024, the

unrealized gain in AOCI was $

million, after-tax (December 31, 2023 – $

million, after-tax). For the

year ended December 31, 2024, unrealized gains of $

million (2023 – $

million) have been reclassified

from AOCI into interest expense, net. The Company expects

million of unrealized gains currently in

AOCI to be reclassified into net income within the next

twelve months.

Regulatory Deferral

The Company has recorded the following changes with

respect to derivatives receiving regulatory

deferral:

Commodity

Physical

Commodity

swaps and

natural gas

swaps and

millions of dollars

forwards

purchases

forwards

For the year ended December 31

2024

2023

Unrealized gain (loss) in regulatory assets

(27)

(109)

(3)

Unrealized gain (loss) in regulatory liabilities

(3)

(73)

Realized gain in regulatory assets

(8)

(5)

Realized loss in regulatory liabilities

Realized (gain) loss in inventory

(1)

(8)

(10)

Realized (gain) loss in regulated fuel for generation

and purchased power

(2)

(6)

(49)

(9)

(4)

Other

(14)

Total

change in derivative instruments

(52)

(204)

(17)

(1) Realized (gains) losses will be recognized in

fuel for generation and purchased power when

the hedged item is consumed.

(2) Realized (gains) losses on derivative instruments

settled and consumed in the period and hedging relationships

that have been

terminated or the hedged transaction is no longer

probable.

As at December 31, 2024, the Company had the following

notional volumes designated for regulatory

deferral that are expected to settle as outlined below:

millions

2025

2026-2027

Physical natural gas purchases:

Natural gas (MMBtu)

Commodity swaps and forwards purchases:

Natural gas (MMBtu)

Power (MWh)

Coal (metric tonnes)

FX forwards:

FX contracts (millions of USD)

208

Weighted average rate

1.3361

1.3296

% of USD requirements

50%

17%

HFT Derivatives

The Company has recognized the following realized and

unrealized gains (losses) with respect to HFT

derivatives:

For the

Year ended December 31

millions of dollars

2024

2023

Power swaps and physical contracts in non-regulated operating revenues

(6)

Natural gas swaps, forwards, futures and physical contracts in non-regulated

operating revenues

195

1,043

Total

gains in net income

207

1,037

As at December 31, 2024, the Company had the following

notional volumes of outstanding HFT

derivatives that are expected to settle as outlined below:

2029 and

millions

2025

2026

2027

2028

thereafter

Natural gas purchases (Mmbtu)

262

111

Natural gas sales (Mmbtu)

299

Power purchases (MWh)

Power sales (MWh)

Other Derivatives

As at December 31, 2024, the Company had equity

derivatives in place to manage cash flow risk

associated with forecasted future cash settlements of deferred

compensation obligations and FX forwards

in place to manage cash flow risk associated with forecasted

USD cash inflows.

The equity derivatives

hedge the return on

2.9

million shares and extends until December 2025. The

FX forwards have a

combined notional amount of $

520

million USD and expire in 2025 through 2026.

For the

Year ended December 31

millions of dollars

2024

2023

Equity

Forwards

Derivatives

Forwards

Derivatives

Unrealized gain (loss) in OM&G

(2)

Unrealized gain (loss) in other income, net

(44)

Realized gain (loss) in OM&G

(13)

Realized loss in other income, net

(12)

(11)

Total

gains (losses) in net income

(56)

(9)

Credit Risk

The Company is exposed to credit risk with respect to

amounts receivable from customers, energy

marketing collateral deposits and derivative assets. Credit risk

is the potential loss from a counterparty’s

non-performance under an agreement. The Company manages

credit risk with policies and procedures

for counterparty analysis, exposure measurement, and

exposure monitoring and mitigation. Credit

assessments are conducted on all new customers and

counterparties, and deposits or collateral are

requested on any high-risk accounts.

The Company assesses the potential for credit losses

on a regular basis and, where appropriate,

maintains provisions. With respect to counterparties, the Company

has implemented procedures to

monitor the creditworthiness and credit exposure of counterparties

and to consider default probability in

valuing the counterparty positions. The Company monitors

counterparties’ credit standing, including those

that are experiencing financial problems, have significant swings

in default probability rates, have credit

rating changes by external rating agencies, or have changes

in ownership. Net liability positions are

adjusted based on the Company’s current default probability.

Net asset positions are adjusted based on

the counterparty’s current default probability.

The Company assesses credit risk internally for

counterparties that are not rated.

As at December 31, 2024, the maximum exposure the

Company had to credit risk was $

1.3

billion (2023

– $

1.2

billion), which included accounts receivable net

of collateral/deposits and assets related to

derivatives.

It is possible that volatility in commodity prices could cause

the Company to have material credit risk

exposures with one or more counterparties. If such counterparties

fail to perform their obligations under

one or more agreements, the Company could suffer

a material financial loss. The Company transacts with

counterparties as part of its risk management strategy for managing

commodity price, FX and interest

rate risk. Counterparties that exceed established credit

limits can provide a cash deposit or letter of credit

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

contractually required. The total cash

deposits/collateral on hand as at December 31, 2024 was

303

million (2023 – $

310

million), which

mitigated the Company’s maximum credit risk

exposure. The Company uses the cash as payment for the

amount receivable or returns the deposit/collateral to the

customer/counterparty where it is no longer

required by the Company.

The Company enters into commodity master arrangements

with its counterparties to manage certain

risks, including credit risk to these counterparties. The

Company generally enters into International Swaps

and Derivatives Association agreements, North American Energy

Standards Board agreements and, or

Edison Electric Institute agreements. The Company believes

entering into such agreements offers

protection by creating contractual rights relating to creditworthiness,

collateral, non-performance and

default.

As at December 31, 2024, the Company had $

140

million (2023 – $

142

million) in financial assets,

considered to be past due, which have been outstanding for

an average

days. The FV of these

financial assets was $

128

million (2023 – $

127

million), the difference of which was included

in the

allowance for credit losses. These assets primarily relate

to accounts receivable from electric and gas

revenue.

Concentration Risk

The Company's concentrations of risk consisted of the

following:

As at

December 31, 2024

December 31, 2023

millions of

dollars

% of total

exposure

millions of

dollars

% of total

exposure

Receivables, net

Regulated utilities:

Residential

376

22%

476

31%

Commercial

184

11%

194

13%

Industrial

Other

105

103

Cash collateral

784

46%

951

62%

Trading group:

Credit rating of A- or above

Credit rating of BBB- to BBB+

Not rated

165

10%

108

295

17%

188

12%

Other accounts receivable

331

20%

151

10%

Classification as assets held for sale

(1)

118

1,528

90%

1,290

84%

Derivative Instruments

(current and long-term)

Credit rating of A- or above

138

Credit rating of BBB- to BBB+

Not rated

166

10%

240

16%

1,694

100%

1,530

100%

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

sale of NMGC. As at December 31, 2024

NMGC's assets and liabilities were

classified as held for sale. For further details, refer

to note 4.

Cash Collateral

The Company’s cash collateral positions consisted

of the following:

As at

December 31

millions of dollars

2024

2023

Cash collateral provided to others

198

101

Cash collateral received from others

Collateral is posted in the normal course of business based

on the Company’s creditworthiness, including

its senior unsecured credit rating as determined by certain

major credit rating agencies. Certain

derivatives contain financial assurance provisions that require

collateral to be posted if a material adverse

credit-related event occurs. If a material adverse event resulted

in the senior unsecured debt falling below

investment grade, the counterparties to such derivatives

could request ongoing full collateralization.

As at December 31, 2024, the total FV of derivatives

in a liability position was $

617

million (December 31,

2023

–

504

million). If the credit ratings of the Company

were reduced below investment grade, the full

value of the net liability position could be required to be

posted as collateral for these derivatives.

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, 2024

millions of dollars

Level 1

Level 2

Level 3

Total

Assets

Regulatory deferral:

Commodity swaps and forwards

FX forwards

HFT derivatives:

Power swaps and physical contracts

Natural gas swaps, futures, forwards, physical

contracts and related transportation

122

Less: Derivatives classified as held for sale

(1)

Total assets

104

166

Liabilities

Regulatory deferral:

Commodity swaps and forwards

FX forwards

HFT derivatives:

Power swaps and physical contracts

Natural gas swaps, futures, forwards and physical

contracts

(11)

437

515

(9)

110

441

542

Other derivatives:

FX forwards

Equity derivatives

Less: Derivatives classified as held for sale

(1)

Total liabilities

165

441

617

Net assets (liabilities)

(61)

(409)

(451)

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

agreement to sell NMGC. As at December

31, 2024, NMGC's assets and liabilities

were classified as held for sale. For further details

on the pending transaction, refer to note 4

As at

December 31, 2023

millions of dollars

Level 1

Level 2

Level 3

Total

Assets

Regulatory deferral:

Commodity swaps and forwards

FX forwards

HFT derivatives:

Power swaps and physical contracts

(5)

Natural gas swaps, futures, forwards, physical

contracts and related transportation

108

184

131

202

Other derivatives:

FX forwards

Equity derivatives

Total assets

158

240

Liabilities

Regulatory deferral:

Commodity swaps and forwards

FX forwards

HFT derivatives:

Power swaps and physical contracts

Natural gas swaps, futures, forwards and physical

contracts

365

397

365

421

Other derivatives:

FX forwards

Total liabilities

365

504

Net assets (liabilities)

(8)

(331)

(264)

The change in the FV of the Level 3 financial assets and liabilities

for the year ended December 31, 2024

was as follows:

HFT Derivatives

millions of dollars

Power

Natural gas

Total

Assets

Balance, beginning of period

Total

realized and unrealized gains (losses) included in non-regulated operating

revenues

(7)

(2)

Balance, December 31, 2024

Liabilities

Balance, beginning of period

365

Total

realized and unrealized gains (losses) included in non-regulated operating

revenues

Balance, December 31, 2024

437

441

Significant unobservable inputs used in the FV measurement

of Emera’s natural gas and power

derivatives include third-party sourced pricing for instruments based

on illiquid markets. Significant

increases (decreases) in any of these inputs in isolation would result

in a significantly lower (higher) FV

measurement. Other unobservable inputs used include internally

developed correlation factors and basis

differentials; own credit risk; and discount rates.

Internally developed correlations and basis differentials

are reviewed on a quarterly basis based on statistical analysis

of the spot markets in the various illiquid

term markets.

Discount rates may include a risk premium for those

long-term forward contracts with

illiquid future price points to incorporate the inherent uncertainty

of these points. Any risk premiums for

long-term contracts are evaluated by observing similar

industry practices and in discussion with industry

peers.

The Company uses a modelled pricing valuation technique for

determining the FV of Level 3 derivative

instruments. The following table outlines quantitative information

about the significant unobservable

inputs used in the FV measurements categorized within Level

3 of the FV hierarchy:

Significant

Weighted

millions of dollars

Unobservable Input

Low

High

average

(1)

Assets

Liabilities

As at December 31, 2024

HFT derivatives – Power

Third-party pricing

$25.60

$139.65

$82.63

swaps and physical contracts

HFT derivatives – Natural

437

Third-party pricing

$2.20

$17.54

$8.57

gas swaps, futures, forwards

and physical contracts

Total

441

Net liability

409

As at December 31, 2023

HFT derivatives – Natural

365

Third-party pricing

$1.27

$16.25

$4.85

gas swaps, futures, forwards

and physical contracts

Total

365

Net liability

331

(1) Unobservable inputs were weighted by the

relative FV of the instruments.

Long-term debt is a financial liability not measured at

FV on the Consolidated Balance Sheets. The

balance consisted of the following:

As at

Carrying

millions of dollars

Amount

Level 1

Level 2

Level 3

Total

December 31, 2024

18,407

17,941

17,688

253

17,941

December 31, 2023

18,365

16,621

16,363

258

16,621

The Company has designated $

1.2

billion USD denominated Hybrid Notes as a hedge of the

foreign

currency exposure of its ne

t investment

in USD denominated operations. The Company’s Hybrid Notes

are contingently convertible into preferred shares in the

event of bankruptcy or other related events. A

redemption option on or after June 15, 2026 is available

and at the control of the Company.

The Hybrid

Notes are classified as Level 2 financial assets. As at

December 31, 2024, the FV of the Hybrid Notes

was $

1.2

billion (2023 – $

1.2

billion). An after-tax foreign currency loss of $

139

million was recorded in

AOCI for the year ended December 31, 2024 (2023

– $

million after-tax gain).

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

a recovery of $

324

million for the year ended December 31, 2024 (2023

–

163

million expense). NSPML is accounted for as an

equity investment, and therefore corresponding

earnings related to this revenue are reflected in Income

from equity investments.

●

Natural gas transportation capacity purchases from M&NP

are reported in the Consolidated

Statements of Income. Purchases from M&NP reported

net in Operating revenues, Non-regulated,

totalled $

million for the year ended December 31, 2024 (2023

– $

million).

There were no significant receivables or payables between

Emera and its associated companies reported

on Emera’s Consolidated Balance Sheets as at December

31, 2024 and at December 31, 2023.

19. RECEIVABLES AND OTHER CURRENT ASSETS

As at

December 31

millions of dollars

2024

2023

Customer accounts receivable – billed

834

805

Customer accounts receivable – unbilled

342

363

Capitalized transportation capacity

(1)

216

358

Cash collateral provided to others

198

101

Prepaid expenses

105

Income tax receivable

Allowance for credit losses

(12)

(15)

Other

106

Total

receivables and other current assets

1,811

1,817

(1) Capitalized transportation capacity represents the

value of transportation/storage received by EES

on asset management

agreements at the inception of the contracts. The

asset is amortized over the term of each contract.

20. LEASES

Lessee

The Company has operating leases for buildings, land, telecommunication services, and rail cars.

Emera’s leases have remaining lease terms of 1 year to 61 years, some of which include options to

extend the leases for up to 65 years. These options are included as part of the lease term when it is

considered reasonably certain they will be exercised.

As at

December 31

millions of dollars

Classification

2024

2023

Right-of-use asset

Other long-term assets

Lease liabilities

Current

Other current liabilities

Long-term

Other long-term liabilities

Total

lease liabilities

The Company recorded lease expense of $

123

million for the year ended December 31, 2024 (2023

–

127

million), of which $

112

million (2023 – $

119

million) related to variable costs for power generation

facility finance leases, recorded in “Regulated fuel for

generation and purchased power” in the

Consolidated Statements of Income.

Future minimum lease payments under non-cancellable operating

leases for each of the next five years

and in aggregate thereafter are as follows:

millions of dollars

2025

2026

2027

2028

2029

Thereafter

Total

Minimum lease payments

115

132

Less imputed interest

(75)

Total

Additional information related to Emera's leases is as follows:

Year ended December 31

For the

2024

2023

Cash paid for amounts included in the measurement of lease liabilities:

Operating cash flows for operating leases (millions of dollars)

Right-of-use assets obtained in exchange for lease obligations:

Operating leases (millions of dollars)

Weighted average remaining lease term (years)

Weighted average discount rate-

operating leases

3.96%

3.93%

Lessor

The Company’s net investment in direct finance

and sales-type leases primarily relates to Brunswick

Pipeline, Seacoast, compressed natural gas (“CNG”)

stations, a renewable natural gas (“RNG”) facility

and heat pumps.

The Company manages its risk associated with the residual

value of the Brunswick Pipeline lease

through proper routine maintenance of the asset.

Customers have the option to purchase CNG station assets

by paying a make-whole payment at the date

of the purchase based on a targeted internal rate of return

or may take possession of the CNG station

asset at the end of the lease term for no cost. Customers

have the option to purchase heat pumps at the

end of the lease term for a nominal fee.

Commencing in October 2023, the Company leased a RNG

facility to a biogas producer that is classified

as a sales-type lease. The term of the facility lease is

15 years

, with a nominal value purchase at the end

of the term and a net investment of approximately $

million USD.

Direct finance and sales-type lease unearned income is recognized

in income over the life of the lease

using a constant rate of interest equal to the internal

rate of return on the lease and is recorded as

“Operating revenues – regulated gas” and “Other income,

net” on the Consolidated Statements of

Income.

The total net investment in direct finance and sales-type

leases consist of the following:

As at

December 31

millions of dollars

2024

2023

Total

minimum lease payment to be received

1,310

1,360

Less: amounts representing estimated executory costs

(182)

(190)

Minimum lease payments receivable

1,128

1,170

Estimated residual value of leased property (unguaranteed)

183

Less: Credit loss reserve

(2)

Less: unearned finance lease income

(655)

(693)

Net investment in direct finance and sales-type leases

654

658

Principal due within one year (included in "Receivables and other

current assets")

Net Investment in direct finance and sales type leases – long-term

610

621

As at December 31, 2024, future minimum lease payments

to be received for each of the next five years

and in aggregate thereafter were as follows:

millions of dollars

2025

2026

2027

2028

2029

Thereafter

Total

Minimum lease payments to be

received

100

819

1,310

Less: executory costs

(182)

Total

1,128

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

2024 (1)

2023

Generation

131

14,297

13,500

Transmission

3,106

2,835

Distribution

8,512

7,417

Gas transmission and distribution

4,658

5,536

General plant and other

(2)

3,078

2,985

Total

cost

33,651

32,273

Less: Accumulated depreciation

(2)

(10,442)

(9,994)

23,209

22,279

Construction work in progress

(2)

2,959

2,097

Net book value

26,168

24,376

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

agreement to sell NMGC. As at December

31, 2024, NMGC's assets and liabilities

were classified as held for sale and excluded from

the table above.

For further details on the pending transaction, refer

to note 4.

(2) SeaCoast owns a

% undivided ownership interest in a jointly

owned

-mile pipeline lateral located in Florida, which went

into

service in 2020. At December 31, 2024, SeaCoast’s

share of plant in service was $

million USD (2023 – $

million USD), and

accumulated depreciation of $

million USD (2023 – $

million USD). SeaCoast’s undivided ownership interest

is financed with its

funds and all operations are accounted for as

if such participating interest were a wholly

owned facility. SeaCoast’s share of direct

expenses of the jointly owned pipeline is included

in "OM&G" in the Consolidated Statements

of Income.

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

2024

2023

DB pension

plans

Non-pension

benefit plans

DB pension

plans

Non-pension

benefit plans

Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation

("APBO"):

Balance, January 1

2,273

227

2,158

243

Service cost

Plan participant contributions

Interest cost

110

111

Plan amendments

(14)

Benefits paid

(153)

(21)

(147)

(29)

Actuarial losses (gains)

(1)

(3)

146

Settlements and curtailments

(8)

FX translation adjustment

(23)

(5)

Balance, December 31

2,367

241

2,273

227

Change in plan assets:

Balance, January 1

2,298

2,163

Employer contributions

Plan participant contributions

Benefits paid

(153)

(21)

(147)

(29)

Actual return on assets, net of expenses

226

262

Settlements and curtailments

(8)

FX translation adjustment

(20)

(1)

Balance, December 31

2,493

2,298

Funded status, end of year

126

(187)

(179)

(1) The actuarial losses recognized in the period

are primarily due to changes in the discount

rate, higher than expected indexation,

and compensation-related assumption changes.

Plans with PBO/APBO

in Excess of Plan Assets:

The aggregate financial position for pension plans where

the PBO or APBO (for post-retirement benefit

plans) exceeded the plan assets for the years ended December

31 were as follows:

millions of dollars

2024

2023

DB pension

plans

Non-pension

benefit plans

DB pension

plans

Non-pension

benefit plans

PBO/APBO

219

120

205

FV of plan assets

Funded status

(84)

(219)

(83)

(205)

Plans with Accumulated Benefit Obligation (“ABO”)

in Excess of Plan Assets:

The ABO for the DB pension plans was $

2,255

million as at December 31, 2024 (2023 – $

2,172

million).

The aggregate financial position for those plans with an ABO

in excess of the plan assets for the years

ended December 31 were as follows:

millions of dollars

2024

2023

DB pension

plans

DB pension

plans

ABO

114

FV of plan assets

Funded status

(79)

(77)

Balance Sheet:

The amounts recognized in the Consolidated Balance Sheets

consisted of the following:

As at

December 31

millions of dollars

2024

2023

DB pension

plans

Non-pension

benefit plans

DB pension

plans

Non-pension

benefit plans

Other current liabilities

(5)

(21)

(5)

(18)

Liabilities associated with assets held for

sale

(1)

Long-term liabilities

(78)

(196)

(78)

(187)

Other long-term assets

208

108

Assets held for sale

(1)

AOCI, net of tax and regulatory assets

354

385

Deferred income tax expense in AOCI

(8)

(1)

(8)

(1)

Net amount recognized

472

(166)

402

(160)

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

agreement to sell NMGC. As at December

31, 2024, NMGC's assets and liabilities

were classified as held for sale. For further details

on the pending transaction, refer to note 4.

Amounts Recognized in AOCI and Regulatory Assets:

Unamortized gains and losses and past service costs

arising on post-retirement benefits are recorded in

AOCI or regulatory assets. The following table summarizes

the change in AOCI and regulatory assets:

Regulatory assets

Actuarial

(gains) losses

Past service

gains

millions of dollars

DB Pension Plans:

Balance, January 1, 2024

324

Amortized in current period

(9)

(3)

Current year additions

(67)

Change in FX rate

Balance, December 31, 2024

363

(17)

Non-pension benefits plans:

Balance, January 1, 2024

(8)

(2)

Amortized in current period

Current year reductions

(5)

(1)

Change in FX rate

Balance, December 31, 2024

(8)

As at

December 31

millions of dollars

2024

2023

DB pension

plans

Non-pension

benefit plans

DB pension

plans

Non-pension

benefit plans

Actuarial (gains) losses

(17)

(8)

Past service gains

(2)

Deferred income tax expense

AOCI, net of tax

(9)

(7)

(9)

Regulatory assets

363

324

AOCI, net of tax and regulatory assets

354

385

Benefit Cost Components:

Emera's net periodic benefit cost included the following:

As at

Year ended December 31

millions of dollars

2024

2023

DB pension

plans

Non-pension

benefit plans

DB pension

plans

Non-pension

benefit plans

Service cost

Interest cost

110

111

Expected return on plan assets

(160)

(2)

(161)

(2)

Current year amortization of:

Actuarial losses (gains)

(2)

(3)

Past service gains

(2)

Regulatory assets

(2)

Settlement, curtailments

Total

(3)

(11)

The expected return on plan assets is determined based on

the market-related value of plan assets of

2,571

million as at January 1, 2024 (2023 – $

2,577

million), adjusted for interest on certain cash flows

during the year.

The market-related value of assets is based on a smoothed asset value. Any investment

gains (or losses) in excess of (or less than) the expected return on plan assets are recognized on a

straight-line basis into the market-related value of assets over a multi-year period.

Pension Plan Asset Allocations:

Emera’s investment policy includes discussion

regarding the investment philosophy,

the level of risk

which the Company is prepared to accept with respect

to the investment of the Pension Funds, and the

basis for measuring the performance of the assets. Central to

the policy is the target asset allocation by

major asset categories. The objective of the target asset allocation

is to diversify risk and to achieve asset

returns that meet or exceed the plan’s actuarial

assumptions. The diversification of assets reduces the

inherent risk in financial markets by requiring that assets

be spread out amongst various asset classes.

Further, within each asset class,

a diversification is undertaken through the investment

in a broad range

of investment and non-investment grade securities. Emera’s

target asset allocation is as follows:

Asset Class

Target

Range at Market

Canadian Pension Plans:

Short-term securities

10%

Fixed income

34%

49%

Equities:

Canadian

15%

Non-Canadian

37%

61%

Non-Canadian Pension Plans:

Cash and cash equivalents

10%

Fixed income

29%

49%

Equities

48%

68%

Pension plan assets are overseen by the respective

management pension committees in the sponsoring

companies. All pension investments are in accordance with policies

approved by the respective Board of

Directors of each sponsoring company.

The following tables set out the classification of the methodology

used by the Company to FV its

investments (for more information on the FV hierarchy

and measurement, refer to note 17):

millions of dollars

NAV

Level 1

Level 2

Total

Percentage

As at

December 31, 2024

Cash and cash equivalents

Net in-transits

(27)

(1)

Equity securities:

Canadian equity

109

United States equity

312

Other equity

140

Fixed income securities:

Government

132

Corporate

Other

Mutual funds

Open-ended investments

measured at NAV

(1)

1,142

Common collective trusts

measured at NAV

(2)

519

Total

1,661

586

246

2,493

100

As at

December 31, 2023

Cash and cash equivalents

Net in-transits

(9)

Equity securities:

Canadian equity

United States equity

141

Other equity

112

Fixed income securities:

Government

172

Corporate

Other

Mutual funds

Other

(1)

Open-ended investments

measured at NAV

(1)

1,006

Common collective trusts

measured at NAV

(2)

586

Total

1,592

440

266

2,298

100

(1) Net asset value ("NAV") investments are open-ended registered and non-registered

mutual funds, collective investment trusts,

or pooled funds. NAV’s are calculated at least monthly and the funds honour

subscription and redemption activity regularly.

(2) The common collective trusts are private funds

valued at NAV.

The NAVs are calculated based on bid prices of the underlying

securities. Since the prices are not published to external

sources, NAV is used as a practical expedient. Certain funds invest

primarily in equity securities of domestic and

foreign issuers while others invest in long duration

U.S. investment grade fixed

income assets and seeks to increase return through

active management of interest rate and

credit risks. The funds honour

subscription and redemption activity regularly.

Non-Pension Benefit Plans:

There are no assets set aside to pay for most of the Company’s

non-pension benefit plans. As is common

practice, post-retirement health benefits are paid from

general accounts as required. The exception to this

is the NMGC Retiree Medical Plan, which is fully funded.

Investments in Emera:

As at December 31, 2024 and 2023, assets related to the

pension funds and post-retirement benefit plans

did not hold any material investments in Emera or its subsidiaries

securities. However,

as a significant

portion of assets for the benefit plan are held in pooled

assets, there may be indirect investments in these

securities.

Cash Flows:

The following table shows expected cash flows for DB pension

and other post-retirement benefit plans:

millions of dollars

DB pension

plans

Non-pension

benefit plans

Expected employer contributions

2025

Expected benefit payments

2025

175

2026

179

2027

182

2028

184

2029

186

2030 – 2034

950

103

Assumptions:

The following table shows the assumptions that have been

used in accounting for DB pension and other

post-retirement benefit plans:

2024

2023

(weighted average assumptions)

DB pension

plans

Non-pension

benefit plans

DB pension

plans

Non-pension

benefit plans

Benefit obligation – December 31:

Discount rate - past service

5.07

4.91

4.89

Discount rate - future service

5.12

5.00

4.88

4.89

Rate of compensation increase

3.73

3.72

3.87

3.85

Health care trend

- initial (next year)

6.53

6.04

- ultimate

3.77

3.76

- year ultimate reached

2044

2043

Benefit cost for year ended December 31:

Discount rate - past service

4.89

5.33

5.31

Discount rate - future service

4.88

4.89

5.34

5.32

Expected long-term return on plan assets

6.43

3.69

6.56

2.16

Rate of compensation increase

3.87

3.85

3.62

3.61

Health care trend

- initial (current year)

6.04

5.40

- ultimate

3.76

3.77

- year ultimate reached

2043

Actual assumptions used differ by plan.

The expected long-term rate of return on plan assets is based on historical and projected real rates of

return for the plan’s current asset allocation, and assumed inflation. A real rate of return is determined for

each asset class. Based on the asset allocation, an overall expected real rate of return for all assets is

determined. The asset return assumption is equal to the overall real rate of return assumption added to

the inflation assumption, adjusted for assumed expenses to be paid from the plan.

The discount rate is based on high-quality long-term corporate

bonds, with maturities matching the

estimated cash flows from the pension plan.

DC Pension Plan:

Emera also provides a DC pension plan for certain employees.

The Company’s contribution for the year

ended December 31, 2024 was $

million (2023 – $

million).

23. GOODWILL

The change in goodwill for the year ended December 31

was due to the following:

millions of dollars

2024

2023

Balance, January 1

5,871

6,012

Change in FX rate

504

(141)

Impairment charges

(214)

Classified as assets held for sale

(1)

(303)

Balance, December 31

5,858

5,871

(1) As at December 31, 2024, NMGC's assets

and liabilities were classified as held for

sale. For further details on the pending

transaction, refer to note 4.

Goodwill is subject to an annual assessment for impairment

at the reporting unit level. The goodwill on

Emera’s Consolidated Balance Sheets at December

31, 2024, related to TECO Energy,

Inc. (reporting

units with goodwill are TEC, PGS, and NMGC).

On August 5, 2024, Emera announced an agreement to sell

NMGC. As the expected transaction

proceeds on the pending sale will be less than the NMGC carrying

amount, the Company performed a

quantitative goodwill impairment assessment for the NMGC

reporting unit. It was determined that the

NMGC carrying amount exceeded the FV of the expected transaction

proceeds, and as a result, a non-

cash goodwill impairment charge of $

210

million, pre-tax, was recorded in Q3 2024, reducing the

NMGC

reporting unit goodwill balance to $

303

million as at December 31, 2024. This non-cash charge

included in “Impairment charges” on the Consolidated

Statements of Income.

In 2024, a qualitative assessment was performed for TEC

given the significant excess of FV over carrying

amounts calculated during the last quantitative test in

Q4 2023. Management concluded it was more likely

than not that the FV of this reporting unit exceeded

its carrying amount, including goodwill. As such, no

quantitative testing was required. Given the length of time

passed since the last quantitative impairment

test for the PGS reporting unit, Emera elected to bypass

a qualitative assessment and performed a

quantitative impairment assessment in Q4 2024 using a combination

of the income and market approach.

This assessment estimated that the FV of the PGS reporting

unit exceeded its carrying amount, including

goodwill, and as a result, no impairment charges were

recognized.

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

2024

Weighted

average

interest rate

2023

Weighted

average

interest rate

Florida Electric Utility

Advances on revolving credit facilities

915

4.77

277

5.68

Gas Utilities and Infrastructure

PGS – Advances on revolving credit facilities

199

5.36

6.36

NMGC – Advances on revolving credit facilities

5.52

6.46

Other Electric Utilities

GBPC – Advances on revolving credit facilities

7.20

5.54

Other

TECO Finance – Advances on revolving credit and term facilities

265

5.53

245

6.54

Emera – Bank indebtedness

Emera – Non-revolving term facilities

796

6.07

1,446

1,433

Adjustment

Classification as liabilities held for sale

(1)

(46)

Short-term debt

1,400

1,433

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

to sell NMGC. As at December 31, 2024,

NMGC's liabilities were classified

as held for sale. For further details on the pending

transaction, refer to note 4.

The Company’s total short-term unsecured revolving

and non-revolving credit facilities, outstanding

borrowings and available capacity as at December 31 were

as follows:

millions of dollars

Maturity

2024

2023

TEC – committed revolving credit facility

2028

1,151

401

TECO Finance – committed revolving credit facility

2028

576

529

PGS – revolving credit facility

2028

360

331

NMGC – revolving credit facility

2026

180

165

Emera – non-revolving term facility

2024

400

Emera – non-revolving term facility

2024

400

TEC – revolving facility

2024

265

TEC – revolving facility

2024

265

Other – committed revolving credit facilities

Various

Total

2,302

2,773

Less:

Advances under revolving credit and term facilities

1,400

1,433

Letters of credit issued within the credit facilities

Total

advances under available facilities

1,404

1,436

Available capacity under existing agreements

898

1,337

The weighted average interest rate on outstanding short-term

debt at December 31, 2024 was

5.05

per

cent (2023 –

5.95

per cent).

Recent Significant Financing Activity by Segment

Florida Electric Utilities

On April 1, 2024, TEC amended its $

800

million USD unsecured committed revolving credit facility

extend the maturity date from

December 17, 2026

December 1, 2028

. There were no other changes in

commercial terms from the prior agreement.

Other

On June 24, 2024, Emera repaid its $

400

million unsecured non-revolving term facility set to mature in

August 2024.

On June 17, 2024, Emera repaid $

200

million on the December 2024 unsecured non-revolving

term

facility, decreasing

the facility from $

400

million to $

200

million. In December 2024, Emera repaid the

200

million upon maturity.

On April 1, 2024, TECO Finance amended its $

400

million USD unsecured committed revolving credit

facility to extend the maturity date from

December 17, 2026

December 1, 2028

. There were no other

changes in commercial terms from the prior agreement.

25. OTHER CURRENT LIABILITIES

As at

December 31

millions of dollars

2024

2023

Accrued charges

189

172

Accrued interest on long-term debt

106

107

Pension and post-retirement liabilities (note 22)

Sales and other taxes payable

Income tax payable

Other

153

112

489

427

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

2024

2023

Maturity

2024

2023

Florida Electric Utility

Senior unsecured notes

4.36%

4.61%

2029 - 2051

5,720

5,654

Canadian Electric Utilities

NSPI – Commercial paper

(2)

Variable

2029

177

721

NSPI – Senior unsecured notes

5.12%

5.13%

2025 - 2097

3,184

3,165

3,361

3,886

Gas Utilities and Infrastructure

PGS – Senior unsecured notes

5.63%

2028 - 2053

1,331

1,223

NMGC – Senior unsecured notes

3.78%

2026 - 2051

698

642

NMGC – Unsecured loan notes

N/A

Variable

2024

NMGI – Senior unsecured notes

N/A

3.64%

2024

198

EBP – Secured loan notes

Variable

2028

250

246

2,279

2,339

Other Electric Utilities

Unsecured loan notes

4.06%

4.78%

2025 - 2028

143

121

Unsecured loan notes

Variable

2025 - 2027

104

Secured senior notes and debentures

(3)

2.38%

3.06%

2026 - 2040

169

197

416

422

Other

Unsecured loan notes

Variable

2026 - 2029

992

465

Senior unsecured notes

3.99%

3.65%

2026 - 2046

3,525

3,637

Senior unsecured notes

4.84%

2030

500

Fixed to floating subordinated notes

(4)

6.75%

2076

1,727

1,587

Junior subordinated notes

7.63%

0.00%

2054

720

7,464

6,189

Adjustments

Debt issuance costs

(137)

(125)

Classification as liabilities held for sale

(5)

(696)

Amount due within one year

(6)

(234)

(676)

(1,067)

(801)

Long-Term Debt

18,173

17,689

(1) Weighted average interest rate of fixed rate long-term debt.

(2) Discount notes are backed by a revolving

credit facility which matures in 2029.

(3) Notes are issued and payable in either USD

or BBD.

(4) In 2024, the Company recognized $

110

million in interest expense (2023 – $

109

million) related to its fixed to floating

subordinated notes.

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

agreement to sell NMGC. As at December

31, 2024, NMGC's liabilities were

classified as held for sale.

For further details on the pending transaction,

refer to note 4.

(6) Excludes NMGC amounts which are classified

as current liabilities associated with assets held

for sale.

The Company’s total long-term revolving credit facilities,

outstanding borrowings and available capacity as

at December 31 were as follows:

millions of dollars

Maturity

2024

2023

Emera – committed revolving credit facility

(1)

June 2029

1,300

900

NSPI – revolving credit facility

(1)

June 2029

800

Emera – Unsecured non-revolving credit facility

February 2026

200

400

TEC – Unsecured committed revolving credit facility

December 2026

657

NSPI – non-revolving credit facility

July 2024

400

NMGC – Unsecured non-revolving credit facility

March 2024

ECI – revolving credit facilities

October 2024

Total

2,300

3,197

Less:

Borrowings under credit facilities

1,169

1,884

Letters of credit issued inside credit facilities

Use of available facilities

1,181

1,890

Available capacity under existing agreements

1,119

1,307

(1) Advances on the revolving credit facility can be

made by way of overdraft on accounts up to

million.

Debt Covenants

Emera and its subsidiaries have debt covenants associated

with their credit facilities. Covenants are

tested regularly and the Company is in compliance with

covenant requirements. Emera’s significant

covenants are listed below:

As at

Financial Covenant

Requirement

December 31, 2024

Emera

Syndicated credit facilities

Debt to capital ratio

Less than or equal to

0.70

to 1

0.55

: 1

Recent Significant Financing Activity by Segment

Florida Electric Utility

On July 12, 2024, TEC repaid a $

300

million USD note upon maturity.

This note was repaid with

proceeds from commercial paper.

On January 30, 2024, TEC issued $

500

million USD of senior unsecured bonds that bear interest

4.90

per cent with a maturity date of

March 1, 2029

. Proceeds from the issuance were primarily used for the

repayment of short-term borrowings outstanding under the

-year credit facility.

Canadian Electric Utilities

On June 24, 2024, NSPI amended its unsecured non-revolving

credit facility to extend the maturity date

from

July 15, 2024

June 24, 2025

and reduce the facility from $

400

million to $

300

million. On

December 16, 2024, NSPI repaid the $

300

million unsecured non-revolving credit facility.

On June 24, 2024, NSPI amended its unsecured committed

revolving credit facility to extend the maturity

date from

December 16, 2027

June 24, 2029

. There were no other material changes in commercial

terms from the prior agreement.

On June 13, 2024, NSPI entered a non-revolving credit

facility to finance the Battery Energy Storage

Project. NSPI can request funds under the facility quarterly

for amounts related to incurred project costs

up to the total commitment of the lessor of $

120

million and

45.06

per cent of the total eligible project

costs over the term of the agreement. The facility will be

available until

months after completion of the

project, not to exceed

May 21, 2027

, and matures

years following the end of the period. As at

December 31, 2024, NSPI had utilized $

million from the facility,

which bears interest at

2.51

per cent.

Gas Utilities and Infrastructure

On December 10, 2024, Brunswick Pipeline amended

its non-revolving loan agreement. The maturity

date was extended to December 2028 and now includes

annual principal repayments.

On July 30, 2024, New Mexico Gas Intermediate, Inc. repaid

its $

150

million USD fixed rate notes upon

maturity.

Other Electric Utilities

On May 2, 2024, BLPC amended its $

million Barbadian dollar ($

million USD) loan facility to extend

the maturity date from

February 19, 2025

July 19, 2028

. There were no other material changes in

commercial terms from the prior agreement.

Other

On June 24, 2024, Emera amended its unsecured committed

revolving credit facility increasing the facility

from $

900

million to $

1,300

million. Emera also extended the maturity date from

June 24, 2027

June

24, 2029

. There were no other material changes in commercial terms

from the prior agreement.

On June 15, 2024, Emera Finance repaid its $

300

million USD senior notes upon maturity.

On June 18, 2024, EUSHI Finance, Inc., completed an issuance

of $

500

million USD fixed-to-fixed reset

rate junior subordinated notes. The notes initially bear

interest at a rate of

7.625

per cent, and will reset

on December 15, 2029, and every

five years

thereafter, to a rate per annum

equal to the five-year U.S.

treasury rate plus

3.136

per cent. The notes mature on

December 15, 2054

. EUSHI Finance, Inc., at its

option, may redeem the notes, in whole or in part,

90 days

prior to the first interest reset date, and any

semi-annual interest payment date thereafter,

at a redemption price equal to the principal amount.

On February 16, 2024, Emera amended its $

400

million unsecured non-revolving facility to extend the

maturity date from

February 19, 2024

February 19, 2025

. There were no other changes in commercial

terms from the prior agreement. On July 19, 2024, Emera reduced

the amount of the facility from $

400

million to $

200

million. On February 20, 2025, Emera extended the agreement

for an additional year to

February 2026 with no other changes in terms. This facility

was classified as long-term debt at December

31, 2024.

Long-Term Debt Maturities

As at December 31, 2024, long-term debt maturities, including

capital lease obligations, for each of the

next five years and in aggregate thereafter are as follows:

millions of dollars

2025

2026

2027

2028

2029

Thereafter

Total

Florida Electric Utility

720

5,000

5,720

Canadian Electric Utilities

125

217

2,979

3,361

Gas Utilities and

Infrastructure

132

535

1,519

2,279

Other Electric Utilities

101

116

416

Other

3,006

792

3,666

7,464

Total

234

3,279

120

651

1,764

13,192

19,240

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

2024

2023

Balance, January 1

192

174

Additions

Accretion included in depreciation expense

Change in FX rate

(1)

Revisions in estimated cash flows

Accretion deferred to regulatory asset (included in PP&E)

Classified as assets held for sale

(1)

Liabilities settled

(2)

(8)

Balance, December 31

217

192

(1) As at December 31, 2024, NMGC's assets

and liabilities were classified as held for

sale. For further details on the pending

transaction, refer to note 4.

28. COMMITMENTS AND CONTINGENCIES

Commitments

As at December 31, 2024, contractual commitments (excluding

pensions and other post-retirement

obligations, long-term debt and asset retirement obligations) for

each of the next five years and in

aggregate thereafter consisted of the following:

millions of dollars

2025

2026

2027

2028

2029

Thereafter

Total

Purchased power

(1)

307

277

368

369

4,487

6,176

Transportation

(2)(3)

742

545

544

454

412

3,228

5,925

Capital projects

604

287

915

Fuel, gas supply and storage

(4)

591

711

Other

160

264

717

2,404

1,298

1,037

886

840

7,979

14,444

As detailed below, contractual obligations at December 31, 2024 includes

those related to NMGC. On completion of

the sale of

NMGC, all remaining future contractual obligations will

be transferred to the buyer. For further details on the pending

transaction, refer

to note 4.

(1) Annual requirement to purchase electricity production

from IPPs or other utilities over varying contract lengths.

(2) Includes $

million related to NMGC (2025: $

million, 2026: $

million, 2027: $

million, 2028: $

million, 2029: $

million).

(3) Purchasing commitments for transportation of

fuel and transportation capacity on various pipelines.

Includes a commitment of

135

million related to a gas transportation contract between

PGS and SeaCoast through 2040.

(4) Includes $

177

million related to NMGC (2025: $

109

million, 2026: $

million, 2027: $

million, 2028: $

million)

NSPI has a contractual obligation to pay NSPML for use of the

Maritime Link over approximately

38 years

from its January 15, 2018 in-service date. In November

2024, the UARB approved the collection of up to

197

million from NSPI for the recovery of Maritime Link

costs in 2025. The timing and amounts payable

to NSPML for the remainder of the

-year commitment period are subject to UARB

approval.

Emera has committed to obtain certain transmission rights

in New Brunswick during summer periods

(April through October, inclusive)

for NLH's use, if requested, effective August 15,

2021 and continuing for

years. As transmission rights are contracted, the obligations

are included within “Other” in the above

table.

Legal Proceedings

Superfund and Former Manufactured Gas Plant Sites

Previously, TEC had

been a potentially responsible party (“PRP”) for certain superfund

sites through its

Tampa

Electric and former PGS divisions, as well as for certain

former manufactured gas plant sites

through its PGS division. As a result of the separation of the PGS

division into a separate legal entity,

Peoples Gas System, Inc. is also now a PRP for those sites (in

addition to third party PRPs for certain

sites).

While the aggregate joint and several liability associated with

these sites has not changed as a

result of the PGS legal separation, the sites continue to present

the potential for significant response

costs. As at December 31, 2024, the aggregate financial

liability of the Florida utilities is estimated to be

million ($

million USD), primarily at PGS. This estimate assumes

that other involved PRPs are

credit-worthy entities. This amount has been accrued and

is primarily reflected in the long-term liability

section under “Other long-term liabilities” on the Consolidated

Balance Sheets. The environmental

remediation costs associated with these sites are expected

to be paid over many years.

The estimated amounts represent only the portion of the cleanup

costs attributable to the Florida utilities.

The estimates to perform the work are based on the Florida

utilities’ experience with similar work,

adjusted for site-specific conditions and agreements with

the respective governmental agencies. The

estimates are made in current dollars, are not discounted

and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those

PRPs are believed to be currently credit-

worthy and are likely to continue to be credit-worthy for

the duration of the remediation work. However,

those instances that they are not, the Florida utilities could be

liable for more than their actual percentage

of the remediation costs. Other factors that could impact

these estimates include additional testing and

investigation which could expand the scope of the cleanup activities,

additional liability that might arise

from the cleanup activities themselves or changes in

laws or regulations that could require additional

remediation. Under current regulations, these costs are recoverable

through customer rates established

in base rate proceedings.

Other Legal Proceedings

Emera and its subsidiaries may,

from time to time, be involved in other legal proceedings,

claims and

litigation that arise in the ordinary course of business

which the Company believes would not reasonably

be expected to have a material adverse effect on the

financial condition of the Company.

Principal Financial Risks and Uncertainties

Emera believes the following principal financial risks could have

a material adverse effect on Emera or its

subsidiaries, or their business operations, liquidity or access

to or cost of capital, financial position,

prospects, and/or results of operations (herein considered a “Material

Adverse Effect”). Risks associated

with derivative instruments and FV measurements are

discussed in note 16 and note 17.

Sound risk management is an essential discipline for running

the business efficiently and pursuing the

Company’s strategy successfully.

Emera has an enterprise-wide risk management process,

overseen by

its Enterprise Risk Management Committee (“ERMC”)

and monitored by the Board of Directors, to ensure

risks are appropriately identified, assessed, monitored

and subject to appropriate controls. The Board of

Directors has a Risk and Sustainability Committee (‘RSC”)

to assist in carrying out its risk and

sustainability oversight responsibilities. The RSC’s

mandate includes oversight of the Company’s

Enterprise Risk Management framework, including the

identification, assessment, monitoring and

management of enterprise risks.

Regulatory and Political Risk

The Company’s rate-regulated subsidiaries and certain

investments are subject to complex legislative

and regulatory frameworks that cover material aspects

of their businesses. These frameworks influence

key factors such as rates and cost structures, revenue requirements,

allowed ROEs, capital structures,

rate base and capital investments, and the recovery

of purchased electricity and fuel costs and other

costs. Regulators also review the prudency of costs and make

other decisions that can impact customer

rates and the reliability of service. Emera’s cost

-of-service utilities must obtain regulatory approvals for

material aspects of their businesses, including changing

or adding rates and/or riders. Such approvals

often require public hearing proceedings involving numerous

stakeholders, and there is no assurance in

the outcomes or impact of any regulatory process or decision.

If Emera is unable to recover in a timely manner a material

amount of costs or a return on invested capital

through regulatory mechanisms or otherwise, is disallowed

the recovery of certain costs, is subject to

regulatory penalties, is not permitted to make certain capital

investments, or is not permitted to invest in or

divest certain utility assets, it could result in a Material Adverse

Effect, including valuation impairments.

Regulatory lag, the time between the incurrence of costs

and the granting of the rates to recover those

costs by regulators, may also result in a Material Adverse

Effect.

Aspects of the acquisition, ownership, operations, siting, planning,

construction, and decommissioning of

electric generation, storage, transmission and distribution facilities

and natural gas transportation and

distribution systems are also subject to regulatory processes

and approvals of regulators, government

departments and agencies, and other third parties. The failure

to obtain, maintain, and renew such

approvals or significant changes in the terms and conditions

thereof could have a Material Adverse Effect.

The regulatory framework, process and regulatory decisions

may also be adversely affected by changes

in government, shifts in government or public policy,

legislative changes, regulatory decisions, geopolitical

changes, changes in the economic environment, or other

factors. Government interference in the

regulatory process or regulatory decisions can undermine regulatory

stability, predictability,

and

independence. Any such changes could have a Material

Adverse Effect.

Foreign Exchange Risk

The Company is exposed to foreign currency exchange rate changes.

Emera operates internationally,

with a significant amount of the Company’s net

income earned outside of Canada. As such, Emera is

exposed to movements in exchange rates between the

CAD and, particularly,

the USD, which could

positively or adversely affect results.

Emera manages currency risks through matching US denominated

debt to finance its US operations and

may use foreign currency derivative instruments to hedge specific

transactions and earnings exposure.

The Company may enter FX forward and swap contracts

to limit exposure on certain foreign currency

transactions such as fuel purchases, revenue streams

and capital expenditures, and on net income

earned outside of Canada. The regulatory framework for

the Company’s rate-regulated subsidiaries

permits the recovery of prudently incurred costs, including

FX.

The Company does not utilize derivative financial instruments

for foreign currency trading or speculative

purposes or to hedge the value of its investments in foreign subsidiaries.

Exchange gains and losses on

net investments in foreign subsidiaries do not impact net income

as they are reported in AOCI.

Liquidity and Capital Markets

Risk

Liquidity risk relates to Emera’s ability to ensure sufficient

funds are available to meet its financial

obligations. Emera’s access to capital and cost of

borrowing is subject to several risk factors, including

financial market conditions, market disruptions and ratings assigned

by various market analysts, including

credit rating agencies. Disruptions in capital markets could

prevent Emera from issuing new securities or

cause the Company to issue securities with less than preferred

terms and conditions. Emera’s growth

plan requires significant capital investments in PP&E and the

risk associated with changes in interest

rates could have an adverse effect on the cost

of financing. The Company’s future access

to capital and

cost of borrowing may be impacted by various market disruptions

The inability to access cost-effective

capital could have a material impact on Emera’s

ability to fund its growth plan.

Emera is subject to financial risk associated with changes

in its credit ratings. There are a number of

factors that rating agencies evaluate to determine credit

ratings, including the Company’s business,

its

regulatory framework and legislative environment, political

interference in the regulatory process, the

ability to recover costs and earn returns, diversification,

leverage, liquidity and increased exposure to

climate change-related impacts, including increased frequency

and severity of hurricanes and other

severe weather events. A decrease in a credit rating could

result in higher interest rates in future

financings, increased borrowing costs under certain existing

credit facilities, limit access to the

commercial paper market, or limit the availability of adequate

credit support for subsidiary operations. For

certain derivative instruments, if the credit ratings of the Company

were reduced below investment grade,

the full value of the net liability of these positions could

be required to be posted as collateral.

The Company has exposure to its own common share

price through the issuance of various forms of

stock-based compensation, which affect earnings

through revaluation of the outstanding units every

period. The Company uses equity derivatives to reduce

the earnings volatility derived from stock-based

compensation.

General Economic Risk

The Company has exposure to the macro-economic conditions

in North America and in other geographic

regions in which Emera operates. Like most utilities, economic

factors such as consumer income,

employment and housing affect demand for electricity

and natural gas and, in turn, the Company’s

financial results. Adverse changes in general economic

conditions and inflation may impact the ability of

customers to afford rate increases arising from

increases to fuel, operating, capital, environmental

compliance, and other costs, and therefore could have

a Material Adverse Effect. This may also result in

higher credit and counterparty risk, adverse shifts in government

policy and legislation, and/or increased

risk to full and timely recovery of costs and regulatory

assets.

Interest Rate Risk:

Emera utilizes a combination of fixed and floating rate

debt financing for operations and capital

expenditures, resulting in an exposure to interest rate risk.

For Emera’s regulated subsidiaries, the cost of

debt is a component of rates and prudently incurred debt

costs are recovered from customers. Regulatory ROE

will generally follow the direction of interest rates,

such that regulatory ROEs are likely to fall in times of reducing

interest rates and rise in times of

increasing interest rates, albeit not directly and generally with

a lag period reflecting the regulatory

process. Rising interest rates may also negatively affect

the economic viability of project development

and acquisition initiatives.

Interest rates could also be impacted by changes in credit

ratings. For more information, refer to “Liquidity

and Capital Markets

Risk”.

As with most other utilities and other similar yield-returning

investments, Emera’s share price may be

affected by changes in interest rates and could underperform

the market in an environment of rising

interest rates.

Inflation Risk:

The Company may be exposed to changes in inflation that

may result in increased operating and

maintenance costs, capital investment, and fuel costs

compared to the revenues provided by customer

rates.

Commodity Price Risk

The Company’s utility fuel supply and purchase

of other commodities is subject to commodity price risk.

In addition, Emera Energy is subject to commodity price risk

through its portfolio of commodity contracts

and arrangements.

Regulated Utilities:

The Company’s utility fuel supply is exposed to

broader global market conditions, which may include

impacts on delivery reliability and price, despite contracted terms.

Supply and demand dynamics in fuel

markets can be affected by a wide range of factors

which are difficult to predict and may change rapidly,

including but not limited to, currency fluctuations, changes

in global economic conditions, natural

disasters, transportation or production disruptions, and

geo-political risks, such as political instability,

conflicts, changes to international trade agreements, tariffs,

trade sanctions or embargos.

Prolonged and substantial increases in fuel prices could result

in decreased rate affordability,

increased

risk of recovery of costs or regulatory assets, and/or negative

impacts on customer consumption patterns

and sales, any of which could result in a Material Adverse

Effect.

Emera Energy Marketing and Trading:

The majority of Emera Energy’s portfolio of electricity

and gas marketing and trading contracts and, in

particular, its natural gas asset

management arrangements, are contracted on a back

-to-back basis,

avoiding any material long or short commodity positions.

However, the portfolio is

subject to commodity

price risk, particularly with respect to basis point differentials

between relevant markets in the event of an

operational issue, imposition of tariffs or counterparty

default. Changes in commodity prices can also

result in increased collateral requirements associated with

physical contracts and financial hedges,

resulting in higher liquidity requirements and increased costs

to the business.

Income Tax Risk

The computation of the Company’s provision for

income taxes is impacted by changes in tax legislation in

Canada, the US and the Caribbean and any such changes

could have a Material Adverse Effect. The

value of Emera’s existing deferred income tax

assets and liabilities are determined by existing tax laws

and could be negatively impacted by changes in laws.

Guarantees and Letters of Credit

Emera has guarantees and letters of credit on behalf of third

parties outstanding. The following significant

guarantees and letters of credit were not included within

the Consolidated Balance Sheets as at

December 31, 2024

TECO Holdings, Inc. (“TECO Holdings”) has a guarantee

in connection with SeaCoast’s performance

obligations under a gas transportation precedent agreement.

The guarantee is for a maximum potential

amount of $

million USD if SeaCoast fails to pay or perform under the

contract. The guarantee expires

five years after the gas transportation precedent agreement

termination date, which was terminated on

January 1, 2022. The counterparty has the right to require

TECO Holdings to provide replacement credit

support either in the form of a substitute guarantee from

an affiliate with an investment grade credit

rating

or a letter of credit or cash deposit of $

million USD.

TECO Holdings has a guarantee in connection with SeaCoast’s

performance obligations under a firm

service agreement, which expires December 31, 2055,

subject to two extension terms at the option of the

counterparty with a final expiration date of December 31, 2071.

The guarantee is for a maximum potential

amount of $

million USD if SeaCoast fails to pay or perform under the

firm service agreement. The

counterparty has the right to require TECO Holdings to provide

replacement credit support in the form of

either a substitute guarantee from an affiliate

with an investment grade credit rating or a letter of credit

cash deposit of $

million USD.

Emera has a guarantee of $

million USD relating to outstanding notes of ECI. This

guarantee will

automatically terminate on the date upon which the obligations

have been repaid in full.

NSPI has guarantees on behalf of its subsidiary,

NS Power Energy Marketing Incorporated, in the amount

of $

104

million USD (2023 – $

104

million USD) with terms of varying lengths.

The Company has standby letters of credit and surety

bonds in the amount of $

105

million USD

(December 31, 2023 – $

103

million USD) to third parties that have extended credit to

Emera and its

subsidiaries. These letters of credit and surety bonds typically

have a one-year term and are renewed

annually as required.

Emera, on behalf of NSPI, has a standby letter of credit to secure

obligations under a supplementary

retirement plan. The expiry date of this letter of credit was

extended to June 2025. The amount committed

as at December 31, 2024 was $

million (December 31, 2023 – $

million).

Emera has provided an indemnity to a counterparty in

relation to certain future tax amounts that could

arise from specific future changes in Canadian federal

law, subject to certain conditions

and limitations.

No such changes in law have been proposed at this time.

A reasonable estimate of the potential amount

of future payments that could result from future claims

under this indemnity cannot be calculated, but the

risk of having to make any significant payments under

this indemnity is considered to be remote.

Collaborative Arrangements

For the years ended December 31, 2024 and 2023, the

Company has identified the following material

collaborative arrangements:

Through NSPI, the Company is a participant in three

wind energy projects in Nova Scotia. The

percentage ownership of the wind project assets is based on

the relative value of each party’s project

assets by the total project assets. NSPI has power

purchase arrangements to purchase the entire net

output of the projects and, therefore, NSPI’s portion

of the revenues are recorded net within regulated fuel

for generation and purchased power.

NSPI’s portion of operating expenses is recorded

in “OM&G” on the

Consolidated Statements of Income. In 2024, NSPI recognized

million net expense (2023 – $

million) in “Regulated fuel for generation and purchased

power” and $

million (2023 – $

million) in

“OM&G” on the Consolidated Statements of Income.

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, 2024

December 31, 2023

Annual Dividend

Redemption

Issued and

Net

Issued and

Net

Per Share

Price per share

Outstanding

Proceeds

Outstanding

Proceeds

Series A

0.5456

25.00

4,866,814

119

4,866,814

119

Series B

Floating

25.00

1,133,186

Series C

1.6085

25.00

10,000,000

245

10,000,000

245

Series E

1.1250

25.00

5,000,000

122

5,000,000

122

Series F

1.0505

25.00

8,000,000

195

8,000,000

195

Series H

1.5810

25.00

12,000,000

295

12,000,000

295

Series J

1.0625

25.00

8,000,000

196

8,000,000

196

Series L

1.1500

26.00

9,000,000

222

9,000,000

222

Total

58,000,000

1,422

58,000,000

1,422

Characteristics of the First Preferred Shares:

First Preferred Shares

(1)(2)

Annual

Dividend

Rate

(%)

Current

Annual

Dividend

($)

Minimum

Reset

Dividend

Yield (%)

Earliest Redemption

and/or Conversion

Option Date

Redemption

Value

($)

Right to

Convert on

a one for

one basis

Fixed rate reset

(3)(4)

Series A

2.182

0.5456

1.84

August 15, 2025

25.00

Series B

Series C

6.434

1.6085

2.65

August 15, 2028

25.00

Series D

Series F

(5)(6)

4.202

1.0505

2.63

February 15, 2025

25.00

Series G

Minimum rate reset

(3)(4)

Series B

2.393

Floating

1.84

August 15, 2025

25.00

Series A

Series H

6.324

1.5810

4.90

August 15, 2028

25.00

Series I

Series J

4.250

1.0625

4.25

May 15, 2026

25.00

Series K

Perpetual fixed rate

Series E

(7)

4.500

1.1250

25.00

Series L

(8)

4.600

1.1500

November 15, 2026

26.00

(1) Holders are entitled to receive fixed or

floating cumulative cash dividends when declared

by the Board of Directors of the Corporation.

(2) On or after the specified redemption dates,

the Corporation has the option to redeem

for cash the outstanding First Preferred Shares,

whole or in part, at the specified per share redemption

value plus all accrued and unpaid dividends up

to but excluding the dates fixed for

redemption.

(3) On the redemption and/or conversion option

date the reset annual dividend per share

will be determined by multiplying $

25.00

per share

by the annual fixed or floating dividend rate,

which for Series A, C, F and H is the sum

of the five-year Government of Canada

Bond Yield on the applicable reset date, plus the applicable

reset dividend yield (Series H annual

reset rate must be a minimum of

4.90

per

cent) and for Series B equals the Government

of Treasury Bill Rate on the applicable reset date,

plus

1.84

per cent.

(4) On each conversion option date, the holders

have the option, subject to certain conditions,

to convert any or all of their Shares into an

equal number of Cumulative Redeemable

First Preferred Shares of a specified

series. The Company has the right to redeem

the outstanding Preferred Shares, Series

D, Series G and Series I shares without

the consent of the holder every five years

thereafter for

cash, in whole or in part at a price of

25.00

per share plus all accrued and unpaid dividends

up to but excluding the date fixed for redemption

and $

25.50

per share plus all accrued and unpaid dividends

up to but excluding the date fixed for redemption

in the case

of redemptions on any other date after August

15, 2028, February 15, 2025 and August

15, 2028, respectively. The reset dividend yield for

Series I equals the Government of Treasury Bill Rate on

the applicable reset date, plus

2.54

per cent.

(5) On January 8, 2025, Emera announced

that it would not redeem the outstanding Preferred

Shares, Series F on February 15, 2025.

During

the conversion period between January 15,

2025 and January 31,2025, subject to

certain conditions, the holders of Series

F shares had the

right, at their option, to convert all or

any of their Series F shares, on a one-for-one

basis into Cumulative Floating Rate

First Preferred Shares,

Series G on February 15, 2025. On February

6, 2025, Emera announced after having taken

into account all conversion notices received

from

holders, no Series F were converted

into Series G shares.

(6) On January 16, 2025, Emera announced

that the annual fixed dividend per share

for Series F shares will be reset from $

1.0505

to $

1.4372

for the five-year period from and including

February 15, 2025.

(7) First Preferred Shares, Series E are redeemable

at $

25.00

per share.

(8) First Preferred Shares, Series L are redeemable

at $

26.00

on or after November 15, 2026 to

November 15, 2027, decreasing $

0.25

each

year until November 15, 2030 and $

25.00

per share thereafter.

First Preferred Shares are neither redeemable at the option of the shareholder nor have a mandatory

redemption date. They are classified as equity and the associated dividends are deducted on the

Consolidated Statements of Income before arriving at “Net income attributable to common shareholders”

and shown on the Consolidated Statement of Changes in Equity as a deduction from retained earnings.

The First Preferred Shares of each series rank on a parity with the First Preferred Shares of every other

series and are entitled to a preference over the Second Preferred Shares, the Common Shares, and any

other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the

distribution of the remaining property and assets or return of capital of the Company in the liquidation,

dissolution or wind-up, whether voluntary or involuntary.

In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First

Preferred Shares, the holders of the First Preferred Shares, for only so long as the dividends remain in

arrears, will be entitled to attend any meeting of shareholders of the Company at which directors are to be

elected and to vote for the election of two directors out of the total number of directors elected at any such

meeting.

30. NON-CONTROLLING INTEREST IN SUBSIDIARIES

As at

December 31

millions of dollars

2024

2023

Preferred shares of GBPC

Preferred shares of GBPC:

Authorized:

10,000

non-voting cumulative redeemable variable perpetual

preferred shares.

2024

2023

Issued and outstanding:

number of

millions of

dollars

number of

millions of

dollars

Outstanding as at December 31

10,000

GBPC Non–Voting

Cumulative Variable

Perpetual Preferred Stock:

The preferred shares are redeemable by GBPC after June 17, 2021

, at $

1,000

Bahamian per share plus

accrued and unpaid dividends and are entitled to a

6.0 per cent per annum fixed cumulative preferential

dividend to be paid semi-annually

The Preferred Shares rank behind GBPC’s current

and future secured and unsecured debt and ahead of

all of GBPC’s current and future common stock.

31. SUPPLEMENTARY

INFORMATION TO CONSOLIDATED

STATEMENTS

CASH FLOWS

For the

Year ended December 31

millions of dollars

2024

2023

Changes in non-cash working capital:

Inventory

(31)

Receivables and other current assets

(1)

(154)

653

Accounts payable

536

(538)

Other current liabilities

(2)

(179)

Total

non-cash working capital

452

(95)

(1) The year ended December 31, 2023, includes $

162

million related to the January 2023 NMGC gas

hedges. Offsetting change in

regulatory liabilities is included in operating cash

flow before working capital resulting in no

impact to net cash provided by operating

activities.

(2) The year ended December 31, 2023, includes ($

166

) million related to the decreased accrual for

the Nova Scotia Cap-

and-Trade emissions compliance charges. Offsetting regulatory asset (FAM) balance is included

in operating cash flow before

working capital resulting in no impact to net

cash provided by operating activities.

For the

Year ended December 31

millions of dollars

2024

2023

Supplemental disclosure of cash paid:

Interest

989

930

Income taxes

Supplemental disclosure of non-cash activities:

Accrued proceeds from disposal of investment subject to significant influence

Common share dividends reinvested

291

271

Reclassification of short-term debt to long-term debt

657

Decrease in accrued capital expenditures

(19)

Supplemental disclosure of operating activities:

Net change in short-term regulatory assets and liabilities

(118)

123

32. STOCK-BASED COMPENSATION

ECSPP and Common Shareholders DRIP

Eligible employees can participate in the ECSPP. As of December 31, 2024, the plan allows employees

to make cash contributions of a minimum of $25 per month to a maximum of $20,000 CAD or $15,000

USD per year for the purpose of purchasing common shares of Emera. The Company also contributes 20

per cent of the employees’ contributions to the plan.

The plan allows reinvestment of dividends for all participants except for where prohibited by law.

The

maximum aggregate number of Emera common shares

reserved for issuance under this plan is

million

common shares. As at December 31, 2024, Emera was

in compliance with this requirement.

Compensation cost for shares issued under the ECSPP for the

year ended December 31, 2024 was $

million (2023 – $

million) and was included in “OM&G” on the Consolidated

Statements of Income.

The Company also has a Common Shareholders DRIP, which provides an opportunity for shareholders

residing in Canada to reinvest dividends and purchase common shares. This plan provides for a discount

of up to 5 per cent from the average market price of Emera’s common shares for common shares

purchased with the reinvestment of cash dividends. The discount was 2 per cent in 2024.

Stock-Based Compensation Plans

Stock Option Plan

The Company has a stock option plan that grants options to senior management of the Company for a

maximum term of 10 years. The option price of the stock options is the closing price of the Company’s

common shares on the Toronto Stock Exchange on the last business day on which such shares were

traded before the date on which the option is granted. The maximum aggregate number of shares

issuable under this plan is 14.7 million shares. As at December 31, 2024, Emera was in compliance with

this requirement.

Stock options granted in 2021 and prior vest in 25 per cent increments on the first, second, third and

fourth anniversaries of the date of the grant. Stock options granted in 2022 and thereafter vest in 20 per

cent increments on the first, second, third, fourth and fifth anniversaries of the date of the grant. If an

option is not exercised within 10 years, it expires and the optionee loses all rights thereunder. The holder

of the option has no rights as a shareholder until the option is exercised and shares have been issued.

The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and

outstanding common stocks on the date the option is granted.

For stock options granted in 2021 and prior,

unless a stock option has expired, vested options may

exercised within the

27 months

following the option holder’s date of retirement,

six months

following a

termination without just cause or death, and within

sixty days

following the date of termination for just

cause or resignation. Commencing with the 2022 stock

option grant, vested options may be exercised

during the full term of the option following the option holders

date of retirement,

six months

following a

termination without just cause or death, and within

sixty days

following the date of termination for just

cause or resignation. If stock options are not exercised

within such time, they expire.

The Company uses the Black-Scholes valuation model to estimate

the compensation expense related to

its stock-based compensation and recognizes the expense

over the vesting period on a straight-line

basis.

The following table shows the weighted average FV per

stock option along with the assumptions

incorporated into the valuation models for options granted, for

the year-ended December 31:

2024

2023

Weighted average FV per option

4.66

6.32

Expected term

(1)

years

Risk-free interest rate

(2)

3.56

3.53

Expected dividend yield

(3)

6.11

5.05

Expected volatility

(4)

20.67

20.07

(1) The expected term of the option awards is

calculated based on historical exercise behaviour

and represents the period of time

that the options are expected to be outstanding.

(2) Based on the Bank of Canada five-year government

bond yields.

(3) Incorporates current dividend rates and historical

dividend increase patterns.

(4) Estimated using the five-year historical volatility.

The following table summarizes stock option information for

2024:

Total

Options

Non-Vested Options

(1)

Number of

Options

Weighted

average exercise

price per share

Number of

Options

Weighted

average grant

date fair-value

Outstanding as at December 31, 2023

3,095,604

51.20

1,253,255

5.17

Granted

792,600

46.97

792,600

4.66

Exercised

(78,839)

39.86

N/A

Forfeited

(13,325)

56.14

N/A

Vested

N/A

(438,365)

4.58

Options outstanding December 31, 2024

3,796,040

50.53

1,607,490

5.08

Options exercisable December 31, 2024

(2)(3)

2,188,550

50.07

(1) As at December 31, 2024, there was $

million of unrecognized compensation related to

stock options not yet vested which is

expected to be recognized over a weighted

average period of approximately

years (2023 – $

million,

years).

(2) As at December 31, 2024, the weighted

average remaining term of vested options was

years with an aggregate intrinsic value of

million (2023 –

years, $

million).

(3) As at December 31, 2024, the FV of options

that vested in the year was $

million (2023 – $

million).

Compensation cost recognized for stock options for the year

ended December 31, 2024 was $

million

(2023 – $

million), which was included in “OM&G” on the Consolidated

Statements of Income.

As at December 31, 2024, cash received from option exercises

was $

million (2023 – $

million). The

total intrinsic value of options exercised for the year ended

December 31, 2024 was $

million (2023 – $

million). The range of exercise prices for the options outstanding

as at December 31, 2024 was $

39.93

60.03

(2023 – $

32.35

to $

60.03

Share Unit Plans

The Company has DSU, PSU and RSU plans. The plans and the liabilities are marked-to-market at the

end of each period based on an average common share price at the end of the period.

Deferred Share Unit Plans

Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their

compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum

portion of their annual retainer in DSUs. Directors’ fees are paid on a quarterly basis and, at the time of

each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one

Emera common share. When a dividend is paid on Emera’s common shares, the Director’s DSU account

is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns or

otherwise leaves the Board. The cash redemption value of a DSU equals the market value of a common

share at the time of redemption, pursuant to the plan. Following retirement or resignation from the Board,

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

DSUs in the participant’s account by Emera’s closing common share price on the date DSUs are

redeemed.

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

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

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

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

the applicable guidelines are met.

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

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

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

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

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

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

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

participant’s account by the average of Emera’s stock closing price for the fifty trading days prior to a

given calculation date. Payments are made in cash.

In addition, special DSU awards may be made from time to time by the MRCC to selected executives and

senior management to recognize singular achievements or by achieving certain corporate objectives.

A summary of the activity related to employee and director

DSUs for the year ended December 31, 2024

is presented in the following table:

Employee

DSU

Weighted

Average

Grant Date

Director

DSU

Weighted

Average

Grant Date

Outstanding as at December 31, 2023

712,963

42.29

729,058

46.24

Granted including DRIP

86,417

45.20

134,795

48.98

Exercised

(10,292)

38.77

(34,997)

36.04

Outstanding and exercisable as at December 31, 2024

789,088

42.65

828,856

47.12

Compensation cost recognized for employee and director

DSU’s for the year ended December 31, 2024

was $

million (2023 – $

million cost recovery). Tax

benefits related to this compensation cost for share

units realized for the year ended December 31, 2024

were $

million (2023 – $

million tax expense). The

aggregate intrinsic value of the outstanding shares for the year

ended December 31, 2024 for employees

was $

million (2023 – $

million). The aggregate intrinsic value of the outstanding

shares for the year

ended December 31, 2024 for directors was $

million (2023 – $

million). Cash payments made

during the year ended December 31, 2024 associated with

the DSU plan were $

million (2023 – $

million).

Performance Share Unit Plan

Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable

through the plan. PSUs are granted annually for

three-year

overlapping performance cycles, resulting in a

cash payment. Unless otherwise determined by the MRCC, PSUs are granted based on the average of

Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents

are awarded and paid in the form of additional PSUs. The PSU value varies according to the Emera

common share market price and corporate performance.

PSUs vest at the end of the

three-year

cycle and the payouts will be calculated and approved by the

MRCC early in the following year. The value of the payout considers actual service over the performance

cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the

PSU plan, grants may continue to vest in full and payout in normal course post-retirement.

A summary of the activity related to employee PSUs for

the year ended December 31, 2024 is presented

in the following table:

Employee PSU

Weighted Average

Grant Date FV

Aggregate intrinsic value

Outstanding as at December 31, 2023

743,365

55.13

Granted including DRIP

354,793

48.69

Exercised

(253,136)

54.66

Forfeited

(12,929)

52.53

Outstanding as at December 31, 2024

832,093

52.57

Compensation cost recognized for the PSU plan for the

year ended December 31, 2024 was $

million

(2023 – $

million). Tax

benefits related to this compensation cost for share

units realized for the year

ended December 31, 2024 were $

million (2023 – $

million). Cash payments made during the year

ended December 31, 2024 associated with the PSU plan were

million (2023 – $

million).

Restricted Share Unit Plan

Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable

through the plan. RSUs are granted annually for

three-year

overlapping performance cycles, resulting in a

cash payment. Unless otherwise determined by the MRCC, RSUs are granted based on the average of

Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents

are awarded and paid in the form of additional RSUs. The RSU value varies according to the Emera

common share market price.

RSUs vest at the end of the

three-year

cycle and the payouts will be calculated and approved by the

MRCC early in the following year. The value of the payout considers actual service over the performance

cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the

RSU plan, grants may continue to vest in full and payout in normal course post-retirement.

A summary of the activity related to employee RSUs for

the year ended December 31, 2024 is presented

in the following table:

Employee RSU

Weighted Average

Grant Date FV

Aggregate intrinsic value

Outstanding as at December 31, 2023

562,641

55.01

Granted including DRIP

287,976

48.65

Exercised

(183,241)

54.66

Forfeited

(14,228)

52.45

Outstanding as at December 31, 2024

653,148

52.36

Compensation cost recognized for the RSU plan for the

year ended December 31, 2024 was $

million

(2023 – $

million). Tax

benefits related to this compensation cost for share

units realized for the year

ended December 31, 2024 were $

million (2023 – $

million). Cash payments made during the year

ended December 31, 2024 associated with the RSU plan were

million (2023– $

million).

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, 2024

December 31, 2023

Maximum

millions of dollars

Total

assets

exposure to

loss

Total

assets

exposure to

loss

Unconsolidated VIEs in which Emera has variable interests

NSPML (equity accounted)

475

489

34. SUBSEQUENT EVENTS

These financial statements and notes reflect the Company’s

evaluation of events occurring subsequent to

the balance sheet date through February 21, 2025, the date

the financial statements were issued.