EX-99.2

Exhibit 99.2

Management’s Discussion & Analysis

As at February 21, 2025

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

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

“Company”) during the fourth quarter of, and for the full year of, 2024 relative to the same periods in 2023

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

December 31, 2023. The Company’s activities are carried out through five reportable segments: Florida

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

Other.

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

statements and supporting notes as at and for the year ended December 31, 2024.

Emera follows United

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

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

www.sedarplus.ca.

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

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

revenues and expenses. At December 31, 2024, Emera’s rate-regulated subsidiaries and investments

include:

Rate-Regulated Subsidiary or Equity Investment

Accounting Policies Approved/Examined By

Subsidiary

Tampa Electric Company (“TEC”)

Florida Public Service Commission (“FPSC”) and the

Federal Energy Regulatory Commission (“FERC”)

Nova Scotia Power Inc. ("NSPI")

Nova Scotia Utility and Review Board (“UARB”)

Peoples Gas System, Inc. (“PGS”)

FPSC

New Mexico Gas Company, Inc. (“NMGC”)

New Mexico Public Regulation Commission (“NMPRC”)

SeaCoast Gas Transmission, LLC ("SeaCoast")

FPSC

Emera Brunswick Pipeline Company Limited (“Brunswick

Pipeline”)

Canadian Energy Regulator ("CER")

Barbados Light & Power Company Limited (“BLPC”)

Fair Trading Commission, Barbados ("FTC")

Grand Bahama Power Company Limited (“GBPC”)

The Grand Bahama Port Authority (“GBPA”)

Equity Investments

NSP Maritime Link Inc. (“NSPML”)

UARB

Maritimes & Northeast Pipeline Limited Partnership and

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

CER and FERC

St. Lucia Electricity Services Limited (“Lucelec”)

National Utility Regulatory Commission

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

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

dollars (“USD”) unless otherwise stated.

TABLE

OF CONTENTS

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

Introduction and Strategic Overview………….……

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

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

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

Consolidated Financial Highlights………………

Consolidated Income Statement Highlights……

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

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

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

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

Other Electric Utilities ……………………………

Other……………………………………………….

Consolidated Balance Sheet Highlights…………..

Other Developments…………………………………

Financial Highlights……………………………..…..

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

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

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

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

Other…………………………………………….….

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

Consolidated Cash Flow Highlights…..…………

Working Capital……………………………………

Contractual Obligations…………………………..

Forecasted Consolidated Capital Investments…

Debt Management………………………………..

Credit Ratings……………………………………..

Guaranteed Debt………………………………….

Outstanding Stock Data………………………….

Pension Funding……………………………………..

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

Dividend Payout Ratio……………………………….

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

Enterprise Risk and Risk Management……………

Risk Management including Financial

Instruments…………………………………………

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

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

Changes in Accounting Policies and Practices…...

Future Accounting Pronouncements……………

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

FORWARD

-LOOKING INFORMATION

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

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

the expected timing and outcome of the pending sale of NMGC, business prospects and opportunities,

and may not be appropriate for other purposes within the meaning of applicable Canadian securities laws.

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

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

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

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

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

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

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

performance or results will be achieved.

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

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

could cause results or events to differ from current expectations include, without limitation: regulatory and

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

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

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

costs associated with certain capital investments; expected impacts on Emera of challenges in the global

economy; estimated energy consumption rates; maintenance of adequate insurance coverage; changes

in customer energy usage patterns; developments in technology that could reduce demand for electricity;

climate change risk; weather risk, including higher frequency and severity of weather events; risk of

wildfires; unanticipated maintenance and other expenditures; system operating and maintenance risk;

derivative financial instruments and hedging; interest rate risk; inflation risk; counterparty risk; disruption

of fuel supply; country risks; supply chain risk; environmental risks; foreign exchange (“FX”); regulatory

and government decisions, including changes to environmental legislation, financial reporting and tax

legislation; risks associated with pension plan performance and funding requirements; loss of service

area; risk of failure of information technology (“IT”) infrastructure and cybersecurity risks; uncertainties

associated with infectious diseases, pandemics and similar public health threats; market energy sales

prices; labour relations; and availability of labour and management resources.

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

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

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

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

otherwise.

INTRODUCTION AND STRATEGIC

OVERVIEW

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

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

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

Scotia.

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

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

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

and dividends for shareholders.

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

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

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

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

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

Caribbean and New Mexico at 4 per cent each.

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

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

resiliency, infrastructure modernization,

expansion to address customer growth, integration of

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

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

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

As at

millions of dollars

2025

2026

2027

2028

2029

Total

Capital investment plan

3,420

3,990

4,050

4,380

4,590

20,430

Average consolidated rate base

US operations

21,520

23,340

25,140

27,050

29,400

Canadian operations

7,630

8,000

8,370

8,590

8,870

Total

29,150

31,340

33,510

35,640

38,270

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

on the pending sale of NMGC

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

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

the anticipated sale of NMGC. Generally, Emera’s equity requirements are expected to be funded through

the issuance of preferred equity, and the issuance of common equity through Emera’s dividend

reinvestment plan (“DRIP”) and its at-the-market program (“ATM program”). Maintaining investment-grade

credit ratings is a core strategic priority of the Company.

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

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

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

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

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

section.

NON-GAAP FINANCIAL MEASURES AND RATIOS

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

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

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

below.

Adjusted Net Income, Adjusted EPS – Basic, and Dividend Payout Ratio of

Adjusted Net Income

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

measure by excluding items below from net income attributable to common shareholders. Management

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

investors to better understand and evaluate the business.

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

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

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

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

Other.

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

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

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

Adjusting item impacting all periods:

Mark-to-market (“MTM”) Adjustments:

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

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

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

MTM adjustments are related to the following:

●

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

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

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

marketing and trading transactions;

●

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

equity income;

●

equity securities held in BLPC and Emera Energy; and

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

Adjusting items impacting 2024:

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

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

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

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

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

For further

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

Financing Structure Wind-Up:

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

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

Earnings” and “Other Developments” sections.

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

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

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

Items Affecting Earnings” section.

Charges Related to the Pending Sale of NMGC:

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

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

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

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

Adjusting items impacting 2022:

GBPC Impairment Charge:

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

GBPC due to a decline in the fair value (“FV”) of the reporting unit.

NSPML Unrecoverable Costs:

In Q1 2022, the UARB issued a decision to disallow recovery of $9 million in costs ($7 million after-tax)

included in NSPML’s final capital cost application.

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

Three months ended

Year ended

For the

December 31

millions of dollars (except per share amounts)

2024

2023

2024

2023

2022

Net income attributable to common shareholders

154

289

494

978

945

Gain on sale of LIL, after-tax

(1)

129

Financing structure wind-up

Charges related to wind-down costs and certain asset

impairments, after-tax

(2)

(26)

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

(3)(4)

(225)

MTM (loss) gain, after-tax

(5)

(146)

114

(291)

169

175

GBPC impairment charge

(73)

NSPML unrecoverable costs

(7)

Adjusted net income

246

175

849

809

850

EPS – basic

0.52

1.04

1.71

3.57

3.56

Adjusted EPS – basic

0.84

0.63

2.94

2.96

3.20

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

expense of

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

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

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

in transaction costs,

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

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

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

expense) and $117

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

EBITDA and Adjusted EBITDA

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

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

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

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

capital, and finance working capital requirements.

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

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

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

Reconciliation of Net Income to EBITDA and Adjusted EBITDA:

Three months ended

Year ended

For the

December 31

millions of dollars

2024

2023

2024

2023

2022

Net income

(1)

173

307

568

1,045

1,009

Interest expense, net

248

241

973

925

709

Income tax (recovery) expense

(199)

(159)

128

185

Depreciation and amortization

296

264

1,162

1,049

952

EBITDA

518

863

2,544

3,147

2,855

Gain on sale of LIL, excluding income tax

182

Charges related to wind-down costs and certain asset

impairments, excluding income tax

(32)

Charges related to the pending sale of NMGC,

excluding income tax

(246)

MTM (loss) gain, excluding income tax

(203)

158

(408)

237

248

GBPC impairment charge

(73)

NSPML unrecoverable costs

(7)

Adjusted EBITDA

753

705

3,048

2,910

2,687

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

CONSOLIDATED

FINANCIAL REVIEW

Significant Items Affecting Earnings

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

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

“Non-GAAP Financial Measures and Ratios”.

Financing Structure Wind-Up

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

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

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

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

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

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

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

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

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

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

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

Charges Related to Wind-Down Costs and Certain Asset Impairments

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

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

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

in the Other segment.

Gain on Sale of LIL

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

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

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

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

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

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

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

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

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

Charges Related to the Pending Sale of NMGC

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

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

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

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

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

refer to note 23 in the consolidated financial statements.

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

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

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

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

Earnings Impact of MTM Loss, After-Tax

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

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

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

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

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

Consolidated Financial Highlights

For the

Three months ended

Year ended

millions of dollars

December 31

Adjusted net income

2024

2023

2024

2023

2022

Florida Electric Utility

120

115

644

627

596

Canadian Electric Utilities

232

247

222

Gas Utilities and Infrastructure

267

214

221

Other Electric Utilities

Other

(59)

(71)

(342)

(314)

(218)

Adjusted net income

246

175

849

809

850

Gain on sale of LIL, after-tax

129

Financing structure wind-up

Charges related to wind-down costs and

certain asset impairments, after-tax

(26)

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

(225)

MTM (loss) gain, after-tax

(146)

114

(291)

169

175

GBPC impairment charge

(73)

NSPML unrecoverable costs

(7)

Net income attributable to common shareholders

154

289

494

978

945

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

For the

Three months ended

Year ended

millions of dollars

December 31

Adjusted net income – 2023

175

809

Operating Unit Performance

Increased earnings at NSPI due to increased income tax recovery,

partially offset by higher operating, maintenance and general expenses

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

Increased earnings quarter-over-quarter at Other Electric Utilities

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

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

offset by higher OM&G

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

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

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

optimization revenue, partially offset by higher revenue from new base

rates

(4)

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

and customer growth, partially offset by increased interest expense,

depreciation, OM&G, and income tax expense

Increased earnings at TEC due to higher revenues from customer

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

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

earnings also due to lower income tax expense and lower interest

expense, partially offset by unfavourable weather

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

opportunities in Q1 2023 and less favourable market conditions in 2024

(3)

(16)

Decreased earnings at Bear Swamp primarily due to the recognition of

investment tax credits in 2023

(13)

(20)

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

interest

(16)

(32)

Corporate

Decreased deferred income tax asset valuation allowance due to

utilization of tax loss carryforwards

Increased income tax recovery due to increased loss before provision

for income taxes

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

interest expense, increased total Corporate debt and increased interest

rates

(9)

(38)

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

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

hedges

(16)

(1)

Other Variances

(1)

(15)

Adjusted net income – 2024

246

849

For the

Year ended December 31

millions of dollars

2024

2023

2022

Operating cash flow before changes in working capital

2,194

2,336

1,147

Change in working capital

452

(95)

(234)

Operating cash flow

2,646

2,241

913

Investing cash flow

(2,218)

(2,917)

(2,569)

Financing cash flow

(818)

939

1,555

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

As at

December 31

millions of dollars

2024

2023

2022

Total assets

42,951

39,480

39,742

Total long-term

debt (including current portion)

(1)

18,407

18,365

16,318

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

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

and

note 4 in the consolidated financial statements.

Consolidated Income Statement Highlights

For the

Three months ended

Year ended

millions of dollars

December 31

(except per share amounts)

2024

2023

Variance

2024

2023

Variance

2022

Operating revenues

1,763

1,972

(209)

7,200

7,563

(363)

7,588

Operating expenses

1,524

1,467

(57)

6,120

5,769

(351)

5,959

Income from operations

239

505

(266)

1,080

1,794

(714)

1,629

Other (expense) income, net

(29)

(80)

203

158

145

Interest expense, net

248

241

(7)

973

925

(48)

709

Income tax (recovery) expense

(199)

250

(159)

128

287

185

Net income attributable to

common shareholders

154

289

(135)

494

978

(484)

945

Adjusted net income

246

175

849

809

850

Weighted average shares of

common stock outstanding

(in millions)

294.1

277.7

16.4

289.1

273.6

15.5

265.5

EPS – basic

0.52

1.04

(0.52)

1.71

3.57

(1.86)

3.56

EPS – diluted

0.52

1.04

(0.52)

1.71

3.57

(1.86)

3.55

Adjusted EPS – basic

0.84

0.63

0.21

2.94

2.96

(0.02)

3.20

Adjusted EBITDA

753

705

3,048

2,910

138

2,687

Dividends per common share

declared

0.7250

0.7175

0.0075

2.8775

2.7875

0.0900

2.6775

Dividends per first preferred shares declared:

Series A

0.5456

Series B

1.6966

1.5583

0.1383

0.6869

Series C

1.6085

1.2873

0.3212

1.1802

Series E

1.1250

Series F

1.0505

Series H

1.5810

1.3140

0.2670

1.2250

Series J

1.0625

Series L

1.1500

Operating Revenues

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

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

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

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

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

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

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

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

purchased power).

Operating Expenses

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

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

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

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

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

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

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

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

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

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

Other Income, Net

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

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

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

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

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

sale of NMGC, and lower interest income.

Interest Expense, Net

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

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

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

Income Tax (Recovery) Expense

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

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

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

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

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

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

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

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

pending sale of NMGC.

Net Income and Adjusted Net Income

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

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

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

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

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

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

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

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

interest expense; and decreased earnings at Emera Energy.

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

compared to

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

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

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

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

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

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

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

decreased earnings at Emera Energy.

EPS – Basic and Adjusted EPS – Basic

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

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

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

partially offset by an increase in weighted average shares outstanding.

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

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

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

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

Effect of Foreign Currency Translation

Emera operates in the United States (“US”), Canada and various Caribbean countries and, as such,

generates revenues and incurs expenses denominated in local currencies which are translated into CAD

for financial reporting. Changes in translation rates, particularly in the value of the USD against the CAD,

can positively or adversely affect results.

Results of foreign operations are translated at the weighted average rate of exchange, and assets and

liabilities of foreign operations are translated at period end rates.

The relevant CAD/USD exchange rates

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

Three months ended

Year ended

December 31

2024

2023

2024

2023

Weighted average CAD/USD

1.37

1.36

1.35

Period end CAD/USD exchange rate

1.44

1.32

1.44

1.32

The table below includes Emera’s significant segments whose contributions to adjusted net income are

recorded in USD currency:

Three months ended

Year ended

For the

December 31

millions of USD

2024

2023

2024

2023

Florida Electric Utility

(1)

470

466

Gas Utilities and Infrastructure

(2)(3)

178

142

Other Electric Utilities

Other segment

(4)(5)

(33)

(18)

(131)

(95)

Total

(1)(3)(5)

123

111

552

539

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

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

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

December 31, 2024.

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

denominated debt.

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

USD

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

million

USD MTM gain, after-tax).

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

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

translation of the CAD include the impacts of Corporate FX hedges used to mitigate translation risk of

USD earnings in the Other segment.

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

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

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

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

BUSINESS OVERVIEW AND OUTLOOK

Florida Electric Utility

The Florida Electric Utility segment consists of TEC, a vertically integrated regulated electric utility

engaged in the generation, transmission and distribution of electricity, serving customers in West Central

Florida. TEC has $13 billion USD of assets and approximately 855,000 customers at December 31, 2024.

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

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

20,693 kilometres of distribution facilities. TEC meets the planning criteria for reserve capacity

established by the FPSC, which is a 20 per cent reserve margin over firm peak demand.

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

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

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

investments for clauses.

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

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

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

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

growth in Florida.

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

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

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

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

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

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

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

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

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

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

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

approximately 200 miles north of Tampa, in Taylor

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

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

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

reserve for future recovery.

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

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

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

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

reserve for future recovery.

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

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

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

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

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

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

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

mechanism with the FPSC.

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

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

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

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

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

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

include solar investments,

grid modernization, storm hardening investments, building resilience and

energy storage.

Canadian Electric Utilities

The Canadian Electric Utilities segment includes NSPI and NSPML. NSPI is a vertically integrated

regulated electric utility engaged in the generation, transmission and distribution of electricity and the

primary electricity supplier to customers in Nova Scotia. NSPML is a 100 per cent equity interest in the

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

Nova Scotia.

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

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

NSPI

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

2,422 MW of generating capacity, of which 44 per cent is coal and/or oil-fired; 28 per cent is natural gas

and/or oil; 19 per cent is hydro, wind, or solar; 7 per cent is petroleum coke (“petcoke”) and 2 per cent is

biomass-fueled generation. In addition, NSPI has contracts to purchase renewable energy from

independent power producers (“IPPs”) and community feed-in tariff (“COMFIT") participants, which own

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

representing

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

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

kilometres of distribution facilities.

NLH is obligated to provide NSPI with approximately 900 Gigawatt hours (“GWh”) of energy annually over

35 years. In addition, for the first five years of the NS Block, NLH is obligated to provide approximately

240 GWh of additional energy from the Supplemental Energy Block transmitted through the Maritime

Link. NSPI has the option of purchasing additional market-priced energy from NLH through the Energy

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

NLH for up to 1.8 Terawatt

hours (“TWh”) of energy in any given year and, on average, 1.2 TWh of

energy per year through August 31, 2041.

NSPI’s approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter

average regulated common equity component of up to 40 per cent of approved rate base.

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

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

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

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

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

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

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

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

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

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

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

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

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

incremental NSPML debt

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

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

period beginning on January 1, 2025.

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

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

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

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

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

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

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

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

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

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

regulatory asset to Invest

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

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

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

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

amounts to Invest Nova Scotia quarterly.

In 2025, capital investment, including AFUDC, is expected to be $480 million (2024 – $487 million). NSPI

is primarily investing in capital projects required to support power system reliability and reliable service for

customers.

Environmental Legislation and Regulations

NSPI is subject to environmental laws and regulations set by both the Government of Canada and the

Province. NSPI continues to work with both levels of government to comply with these laws and

regulations to maximize efficiency of emission control measures and minimize customer cost. NSPI

anticipates that costs prudently incurred to achieve legislated compliance will be recoverable under

NSPI’s regulatory framework. NSPI faces risks associated with achieving climate-related and

environmental legislative requirements, including the risk of non-compliance, which could adversely affect

NSPI’s operations and financial performance. For further discussion on these risks and environmental

legislation and regulations, refer to the “Enterprise Risk and Risk Management” section. Recent

developments related to provincial and federal environmental laws and regulations are outlined below.

Clean Electricity Regulations (“CER”):

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

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

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

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

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

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

reach 80 per cent renewable electricity sales by 2030.

Nova Scotia Energy Reform Act:

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

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

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

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

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

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

RER:

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

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

2022. The hearing for the matter is currently scheduled for June 2025.

NSPML

Equity earnings from the Maritime Link are dependent on the approved ROE and operational

performance of NSPML. NSPML’s approved regulated ROE range is 8.75 per cent to 9.25 per cent,

based on an actual five-quarter average regulated common equity component of up to 30 per cent.

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

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

The Maritime Link assets entered service on January 15, 2018, enabling the transmission of energy

between Newfoundland and Nova Scotia, improved reliability and ancillary benefits, supporting the

efficiency and reliability of energy in both provinces. NLH’s NS Block delivery obligations commenced on

August 15, 2021, and the NS Block will be delivered over the next 35 years pursuant to the project

agreements.

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

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

information, refer to the NSPI section above.

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

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

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

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

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

terminate the holdback mechanism in early 2025.

NSPML does not anticipate any significant capital investment in 2025.

Gas Utilities and Infrastructure

The Gas Utilities and Infrastructure segment includes PGS, NMGC, SeaCoast, Brunswick Pipeline and

Emera’s equity investment in M&NP.

PGS is a regulated gas distribution utility engaged in the purchase,

distribution and sale of natural gas serving customers in Florida. NMGC is an intrastate regulated gas

distribution utility engaged in the purchase, transmission, distribution and sale of natural gas serving

customers in New Mexico. SeaCoast is a regulated intrastate natural gas transmission company offering

services in Florida. Brunswick Pipeline is a regulated 145-kilometre pipeline delivering re-gasified

liquefied natural gas from Saint John, New Brunswick, to markets in the northeastern US.

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

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

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

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

PGS

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

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

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

2024.

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

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

for clauses.

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

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

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

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

customer demand and system needs.

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

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

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

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

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

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

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

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

customer growth.

NMGC

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

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

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

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

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

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

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

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

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

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

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

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

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

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

rates became effective October 1, 2024.

Other Electric Utilities

Other Electric Utilities includes Emera (Caribbean) Incorporated (“ECI”), a holding company with

regulated electric utilities. ECI’s regulated utilities include vertically integrated regulated electric utilities of

BLPC on the island of Barbados, GBPC on Grand Bahama Island, and an equity investment in Lucelec

on the island of St. Lucia.

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

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

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

of generation, including renewables and battery storage.

BLPC

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

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

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

regulated return on rate base is 10 per cent.

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

Act

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

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

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

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

In 2021, BLPC submitted a general rate review application to the FTC. In September 2022, the FTC

granted BLPC interim rate relief, allowing an increase in base rates of approximately $1 million USD per

month. On February 15, 2023, the FTC issued a decision on the application which included the following

significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent,

a directive to update the major components of rate base to September 16, 2022, and a directive to

establish regulatory liabilities totalling approximately $71 million USD. On March 7, 2023, BLPC filed a

Motion for Review and Variation (the “Motion”) and applied for a stay of the FTC’s decision, which was

subsequently granted. On November 20, 2023, the FTC issued their decision dismissing the Motion.

Interim rates continue to be in effect through to a date to be determined in a final decision and order.

On December 1, 2023, BLPC appealed certain aspects of the FTC’s February 15 and November 20,

2023 decisions to the Supreme Court of Barbados in the High Court of Justice (the “Court”) and

requested that they be stayed. On December 11, 2023, the Court granted the stay.

BLPC’s position is

that the FTC made errors of law and jurisdiction in their decisions and believes the success of the appeal

is probable, and as a result, the adjustments to BLPC’s final rates and rate base, including any

adjustments to regulatory assets and liabilities, have not been recorded at this time. The appeal is

currently scheduled to be heard in 2025.

BLPC currently operates pursuant to a single integrated license to generate, transmit and distribute

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

requiring multiple licenses for the supply of electricity. In 2021, BLPC reached commercial agreement with

the Government of Barbados for each of the license types, subject to the passage of implementing

legislation. The timing of the final enactment is unknown at this time, but BLPC will work towards the

implementation of the licenses once enacted.

GBPC

With $340 million USD of assets and approximately 19,500 customers, GBPC owns 98 MW of oil-fired

generation, approximately 90 kilometres of transmission facilities and 994 kilometres of distribution

facilities. GBPC’s approved regulatory return on rate base is 8.52 per cent.

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

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

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

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

regulator, regulate GBPC. The GBPA

has opposed the legislated removal of its regulatory authority over

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

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

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

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

Emera.

Other

The Other segment includes business operations that in a normal year are below the required threshold

for reporting as separate segments; and corporate expense and revenue items that are not directly

allocated to the operations of Emera’s subsidiaries and investments.

Business operations in the Other segment include Corporate; Emera Energy Services (EES), a physical

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

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

Block Energy initiated the process to wind-up operations.

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

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

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

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

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

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

of Emera’s subsidiaries and investments.

Earnings from EES are generally dependent on market conditions. In particular, volatility in natural gas

and electricity markets, which can be influenced by weather, local supply constraints and other supply

and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1

and Q4 usually providing the greatest opportunity for earnings. EES is generally expected to deliver

annual adjusted net income of $15 to $30 million USD.

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

the wind-up of Block Energy in 2024.

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

CONSOLIDATED

BALANCE SHEET HIGHLIGHTS

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

2024 include:

Increase

(Decrease)

Total

due to

Other

Increase

held for sale

Increase

millions of dollars

(Decrease)

classification (1)

(Decrease)

Explanation of Other Increase (Decrease)

Assets

Cash and cash equivalents

(371)

(8)

(363)

Decreased due to investment in PP&E, net

repayments on committed credit facilities at

Corporate and NSPI, repayment of short-term

debt at TEC, retirement of long-term debt at

Emera, TEC and New Mexico Gas

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

on Emera common stock. These were partially

offset by cash from operations, proceeds from

debt issuances at TEC and EUSHI Finance,

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

the sale of the LIL equity interest and proceeds

from common shares issued

Derivative instruments

(current and long-term)

(74)

(1)

(73)

Decreased due to reversal of 2023 contracts at

EES, partially offset by higher commodity prices

at NSPI

Regulatory assets (current

and long-term)

322

(34)

356

Increased due to higher storm costs recovery

clause assets at TEC and NSPI, the effect of

FX translation of Emera’s non-Canadian

affiliates, and reclassification of early retired

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

These were partially offset by decreased FAM

balance at NSPI due to the NSPML refund, and

decreased fuel clause recovery balance at TEC

due to higher over-recoveries

Receivables and other assets

(current and long-term)

(150)

220

Increased due to higher cash collateral

positions on derivative instruments and

increased trade receivables as a result of

higher commodity prices at EES, and the effect

of FX translation of Emera's non-Canadian

affiliates. These were partially offset by lower

gas transportation assets at EES and lower

trade receivables at TEC

Assets held for sale (current

and long-term), net of

liabilities

973

PP&E, net of accumulated

depreciation and amortization

1,792

(1,828)

3,620

Increased due to capital additions in excess of

depreciation and the effect of FX translation of

Emera's non-Canadian affiliates, partially offset

by a reclassification of early retired plant to TEC

capital cost recovery regulatory asset

Investments subject to

significant influence

(748)

Decreased primarily due to sale of LIL equity

interest

Goodwill

(13)

(303)

290

Increased due to the effect of FX translation of

Emera's non-Canadian affiliates, partially offset

by the non-cash impairment charge recognized

primarily related to NMGC

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

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

statements.

Increase

(Decrease)

Total

due to

Other

Increase

held for sale

Increase

millions of dollars

(Decrease)

classification (1)

(Decrease)

Explanation of Other Increase (Decrease)

Liabilities and Equity

Short-term debt and long-

term debt (including current

portion)

(742)

751

Increased due the effect of FX translation of

Emera's non-Canadian affiliates, proceeds from

long-term debt issuance at TEC, and issuance

of junior subordinated notes at EUSHI Finance.

These were partially offset by repayment of

Emera’s committed credit facilities using the LIL

transaction proceeds, repayment of short-term

debt at TEC and NSPI, and retirement of long-

term debt at Corporate, TEC, and NMGI

Accounts payable

538

(131)

669

Increased due to storm cost payable at TEC,

the effect of FX translation of Emera’s non-

Canadian affiliates, and increased commodity

prices at EES

Deferred income tax

liabilities, net of deferred

income tax assets

(205)

(167)

(38)

No significant change after removing impact of

held for sale classification

Derivative instruments

(current and long-term)

113

(1)

114

Increased due to new contracts in 2024 and

changes in existing positions at EES, higher FX

forward liability at Corporate due to changes in

the FX hedges, partially offset by higher

commodity prices and settlements of derivative

instruments at NSPI

Regulatory liabilities (current

and long-term)

108

(284)

392

Increased due to effect of FX translation of

Emera’s non-Canadian affiliates and

recognition of fuel cost recovery liabilities at

TEC and NSPI due to over-recovery of fuel

costs

Other liabilities (current and

long-term)

152

(34)

186

Increased due the effect of FX translation of

Emera's non-Canadian affiliates and higher

accrued interest on long-term debt at NSPI

Common stock

580

Increased due to shares issued

Accumulated other

comprehensive income

956

Increased due to the effect of FX translation of

Emera's non-Canadian affiliates

Retained earnings

(335)

Decreased due to dividends paid in excess of

net income

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

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

statements.

OTHER DEVELOPMENTS

Canadian Tax Legislation

Changes

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

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

28, 2023, was enacted.

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

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

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

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

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

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

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

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

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

Pending Sale of NMGC

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

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

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

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

assets and liabilities are classified as held for sale.

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

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

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

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

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

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

2024.

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

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

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

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

Consolidated Statements of Income in Q3 2024.

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

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

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

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

December 31, 2024.

Increase in Common Dividend

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

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

15, 2024.

Sale of LIL Equity Interest

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Appointments

Board of Directors

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

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

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

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

Committee.

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

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

She also

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

Energy and held various senior leadership roles with AES Corporation.

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

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

in Canada and the Americas.

FINANCIAL HIGHLIGHTS

Florida Electric Utility

Three months ended

Year ended

For the

December 31

millions of USD (except as indicated)

2024

2023

2024

2023

Operating revenues – regulated electric

582

613

2,526

2,637

Regulated fuel for generation and purchased power

151

162

622

682

Contribution to consolidated adjusted net income

470

466

Contribution to consolidated adjusted net income - CAD

120

115

644

627

Charges related to wind-down costs and certain asset

impairments, after-tax

(1)

(2)

Contribution to consolidated net income

468

466

Contribution to consolidated net income – CAD

117

115

641

627

Average fuel costs in dollars per MWh

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

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

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

Net Income

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

For the

Three months ended

Year ended

millions of USD

December 31

Contribution to consolidated net income – 2023

466

Decreased operating revenues primarily due to decreased fuel

recovery clause revenue, lower storm surcharge revenue (offset in

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

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

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

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

(31)

(111)

Decreased fuel for generation and purchased power due to lower

natural gas prices

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

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

and higher solar operations, labour, and software maintenance costs

Increased depreciation and amortization due to additions to facilities

and generation projects placed in service

(9)

(32)

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

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

partially offset by higher property taxes

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

production tax credits related to solar facilities

Other

(1)

Contribution to consolidated net income – 2024

468

Operating Revenues – Regulated Electric

Annual electric revenues and sales volumes are summarized in the following table by customer class:

Electric Revenues

Electric Sales Volumes

(millions of USD)

(Gigawatt hours ("GWh"))

2024

2023

2024

2023

Residential

1,507

1,711

10,269

10,307

Commercial

686

803

6,481

6,462

Industrial

162

203

2,019

2,082

Other

(1)

171

(80)

2,276

2,194

Total

2,526

2,637

21,045

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

other utilities.

Regulated Fuel for Generation and Purchased Power

Annual production volumes are summarized in the following table:

Production Volumes (GWh)

2024

2023

Natural gas

18,027

17,843

Solar

2,250

1,748

Purchased power

1,569

1,443

Coal

744

Total

21,878

21,778

TEC’s fuel costs are affected by commodity prices and generation mix that is largely dependent on

economic dispatch of the generating fleet, bringing the lowest cost options on first (renewable energy

from solar or battery storage), such that the incremental

cost of production increases as sales volumes

increase. Generation mix may also be affected by plant outages, plant performance, availability of lower

priced short-term purchased power, availability of renewable solar generation, and compliance with

environmental standards and regulations.

Regulatory Environment

TEC is regulated by the FPSC and is also subject to regulation by the FERC. The FPSC sets rates at a

level that allows utilities such as TEC to collect total revenues or revenue requirements equal to their cost

of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC

rate setting hearings which can occur at the initiative of TEC, the FPSC, or other interested parties.

For

further details on TEC’s regulatory environment, base rates and recovery mechanisms, refer to note 7 in

the consolidated financial statements.

Canadian Electric Utilities

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

transaction, refer to the “Other Developments” section.

Three months ended

Year ended

For the

December 31

millions of dollars (except as indicated)

2024

2023

2024

2023

Operating revenues – regulated electric

479

439

1,855

1,671

Regulated fuel for generation and purchased power

(1)

(216)

234

509

777

Contribution to consolidated net income

232

247

Average fuel costs in dollars per MWh

(2)

(73)

(1) Regulated fuel for generation and purchased power includes NSPI's FAM

deferral on the Consolidated Statements of Income,

however, it is excluded in the segment overview.

(2) 2024 Average fuel costs include the $486 million NSPML Refund which decreased average fuel costs

by $164 per MWh and $43

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

Average fuel costs for the year ended December

31, 2023 include reversal of the $166 million of the Nova Scotia Cap-and-Trade Program

provision which decreased average fuel

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

Program provision reversal,

refer to note 7 in the consolidated financial statements.

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

Three months ended

Year ended

For the

December 31

millions of dollars

2024

2023

2024

2023

NSPI

160

141

Equity investment in NSPML

Equity investment in LIL

Contribution to consolidated net income

232

247

Net Income

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

For the

Three months ended

Year ended

millions of dollars

December 31

Contribution to consolidated net income – 2023

247

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

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

customer in 2023

(1)

184

Decreased regulated fuel for generation and purchased power at NSPI

due to the NSPML Refund

(1)

and decreased commodity prices, partially

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

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

Scotia Cap-and-Trade Program provision

(1)

in 2023

450

268

Increased FAM deferral at NSPI primarily due to the NSPML Refund

(1)

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

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

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

Cap-and-Trade Program provision

(1)

in 2023

(484)

(428)

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

side management program costs at NSPI

(8)

(24)

Decreased income from equity investments due to the sale of LIL

(16)

(34)

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

carryforwards offset to a regulatory deferred income tax liability, partially

offset by decreased tax deductions in excess of accounting depreciation

related to property, plant and equipment

Other

(13)

Contribution to consolidated net income – 2024

232

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

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

refer to note 7 in the

consolidated financial statements.

NSPI

Operating Revenues – Regulated Electric

Annual electric revenues and sales volumes are summarized in the following tables by customer class:

Electric Revenues

Electric Sales Volumes

(millions of dollars)

(GWh)

2024

2023

2024

2023

Residential

997

910

5,096

4,986

Commercial

499

463

3,046

3,053

Industrial

276

219

2,217

2,164

Other

222

239

Total

1,813

1,633

10,581

10,442

Regulated Fuel for Generation and Purchased Power

Annual production volumes are summarized in the following table:

Production Volumes (GWh)

2024

2023

Coal

3,347

3,086

Natural gas

2,317

1,946

Purchased power

620

881

Petcoke

374

553

Oil

132

145

Total non-renewables

6,790

6,611

Purchased power - IPP,

COMFIT and imports

3,464

3,251

Wind, hydro and solar

932

1,149

Biomass

140

128

Total renewables

4,536

4,528

Total production volumes

11,326

11,139

NSPI’s fuel costs are affected by commodity prices and generation mix, which is largely dependent on

economic dispatch of the generating fleet. NSPI brings the lowest cost options on stream first after

renewable energy from IPPs including COMFIT participants, for which NSPI has power purchase

agreements in place, and the NS Block of energy, including the Supplemental Energy Block, which

carries no additional fuel cost outside of the UARB approved annual assessments paid to NSPML for the

use of the Maritime Link.

Generation mix may also be affected by plant outages, carbon pricing programs, including the Nova

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

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

Regulatory Environment - NSPI

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

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

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

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

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

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

Gas Utilities and Infrastructure

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

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

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

Three months ended

Year ended

For the

December 31

millions of USD (except as indicated)

2024

2023

2024

2023

Operating revenues – regulated gas

(1)

317

290

1,160

1,114

Operating revenues – non-regulated

Total operating revenue

320

293

1,175

1,129

Regulated cost of natural gas

289

391

Contribution to consolidated adjusted net income

194

158

Contribution to consolidated adjusted net income – CAD

267

214

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

(2)

(6)

Contribution to consolidated net income

188

158

Contribution to consolidated net income – CAD

259

214

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

million) for the

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

however, it is

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

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

December 31, 2024, respectively.

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

following table:

Three months ended

Year ended

For the

December 31

millions of USD

2024

2023

2024

2023

PGS

120

NMGC

Other

Contribution to consolidated adjusted net income

194

158

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

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

Net Income

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

For the

Three months ended

Year ended

millions of USD

December 31

Contribution to consolidated net income – 2023

158

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

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

NMGC

Decreased asset optimization revenues at NMGC

(8)

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

at NMGC

102

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

recoveries and higher labour cost at PGS

(5)

(31)

Increased depreciation primarily due to asset growth at PGS and the

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

2021 rate case settlement at PGS

(13)

(39)

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

interest rates and increased borrowings to support ongoing operations

and capital investments primarily at PGS

(15)

Increased income tax expense primarily due to increased income

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

increase also due to increased income before provision for income

taxes at NMGC

(13)

(21)

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

(6)

Other

(6)

Contribution to consolidated net income – 2024

188

Operating Revenues – Regulated Gas

Annual gas revenues and sales volumes are summarized in the following tables by customer class:

Gas Revenues

Gas Volumes

(millions of USD)

(millions of Therms)

2024

2023

2024

2023

Residential

520

537

410

414

Commercial

362

315

824

839

Industrial

(1)

1,620

1,615

Other

(2)

163

147

278

266

Total

(3)

1,114

1,068

3,132

3,134

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

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

(3) Total gas revenue

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

Regulated Cost of Natural Gas

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

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

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

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

customers.

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

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

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

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

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

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

Gas Volumes by Type

(millions of Therms)

2024

2023

Transportation

2,434

2,461

System supply

698

673

Total

3,132

3,134

Regulatory Environments

PGS is regulated by the FPSC. The FPSC sets rates at a level that allows utilities such as PGS to collect

total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return

on invested capital.

NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to

collect total revenues equal to its cost of providing service, plus an appropriate return on invested capital.

For further information on PGS’s and NMGC’s regulatory environment and recovery mechanisms, refer to

note 7 in the consolidated financial statements.

Other Electric Utilities

Three months ended

Year ended

For the

December 31

millions of USD (except as indicated)

2024

2023

2024

2023

Operating revenues – regulated electric

107

104

413

390

Regulated fuel for generation and purchased power

215

204

Contribution to consolidated adjusted net income

Contribution to consolidated adjusted net income – CAD

Equity securities MTM (loss) gain

(1)

Contribution to consolidated net income

– CAD

Electric sales volumes (GWh)

323

1,307

1,260

Electric production volumes (GWh)

347

345

1,403

1,362

Average fuel cost in dollars per MWh

159

165

153

150

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

the three months and year ended December 31, 2024.

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

table:

Three months ended

Year ended

For the

December 31

millions of USD

2024

2023

2024

2023

BLPC

GBPC

Other

(1)

(3)

Contribution to consolidated adjusted net income

Net Income

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

For the

Three months ended

Year ended

millions of USD

December 31

Contribution to consolidated net income – 2023

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

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

higher sales volumes.

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

to higher sales volumes at BLPC.

(11)

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

and increased generation maintenance costs at GBPC and BLPC.

(8)

Other

Contribution to consolidated net income – 2024

Regulatory Environments

BLPC is regulated by the FTC. Rates are set to recover prudently incurred costs of providing electricity

service to customers plus an appropriate return on capital invested.

GBPC is regulated by the GBPA. Rates are set to recover prudently incurred costs of providing electricity

service to customers plus an appropriate return on rate base.

For further details on BLPC and GBPC’s regulatory environments and recovery mechanisms, refer to note

7 in the consolidated financial statements.

Other

Three months ended

Year ended

For the

December 31

millions of dollars

2024

2023

2024

2023

Marketing and trading margin

(1) (2)

Other non-regulated operating revenue

Total operating revenues – non-regulated

109

123

Contribution to consolidated adjusted net (loss) income

(59)

(71)

(342)

(314)

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

129

Financing structure wind-up

Charges related to wind-down costs and certain asset

impairments, after-tax

(5)

(23)

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

(217)

MTM (loss) gain, after-tax

(7)

(144)

112

(291)

167

Contribution to consolidated net (loss) income

(146)

(686)

(147)

(1) Marketing and trading margin represents EES's purchases and sales of natural gas and electricity,

pipeline and storage

capacity costs and energy asset management services’ revenues.

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

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

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

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

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

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

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

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

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

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

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

expense) and

$117 million recovery for the year ended December

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

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

Three months ended

Year ended

For the

December 31

millions of dollars

2024

2023

2024

2023

Emera Energy:

EES

Other

(2)

Corporate – see breakdown of adjusted contribution below

(73)

(91)

(360)

(356)

Block Energy

(4)

(13)

(18)

Other

(1)

(4)

Contribution to consolidated adjusted net (loss) income

(59)

(71)

(342)

(314)

Net Income

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

For the

Three months ended

Year ended

millions of dollars

December 31

Contribution to consolidated net (loss) income – 2023

(147)

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

favourable hedging opportunities in Q1 2023 and less favourable

market conditions in 2024, specifically lower natural gas prices and

volatility

(19)

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

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

hedges

(18)

(2)

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

interest expense, increased total debt and increased interest rates

(9)

(38)

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

balances

(5)

(9)

Decreased deferred income tax asset valuation allowance due to the

utilization of tax loss carryforwards

Increased income tax recovery due to increased loss before provision

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

credits related to Bear Swamp facility upgrades in 2023

Gain on sale of LIL, after-tax

129

Financing structure wind-up

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

after-tax

(23)

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

(217)

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

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

lower amortization of gas transportation assets at EES

(254)

(457)

Other

(4)

Contribution to consolidated net (loss) income – 2024

(146)

(686)

Emera Energy

EES derives revenue and earnings from wholesale marketing and trading of natural gas and electricity

within the Company’s risk tolerances, including those related to value-at-risk (“VaR”) and credit exposure.

EES purchases and sells physical natural gas and electricity, the related transportation and transmission

capacity rights, and provides energy asset management services. The primary market area for the natural

gas and power marketing and trading business is northeastern North America, including the Marcellus

and Utica shale supply areas. EES also participates in the US Southeast, Gulf Coast and Midwest, and

Central Canadian and Alberta natural gas markets. Its counterparties include electric and gas utilities,

natural gas producers, electricity generators and other marketing and trading entities. EES operates in a

competitive environment, and the business relies on knowledge of the region’s energy markets,

understanding of pipeline and transmission infrastructure, a network of counterparty relationships and a

focus on customer service. EES manages its commodity risk by limiting open positions, utilizing financial

products to hedge purchases and sales, and investing in transportation capacity rights to enable

movement across its portfolio.

EES’ contribution to consolidated adjusted net income was $16 million in Q4 2024, compared to $19

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

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

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

MTM Adjustments

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

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

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

the table above.

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

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

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

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

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

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

which is amortized over the term of the AMA contract.

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

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

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

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

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

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

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

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

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

Consolidated Statements of Income.

Corporate

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

Three months ended

Year ended

For the

December 31

millions of dollars

2024

2023

2024

2023

Operating expenses

(1)

(23)

(7)

(74)

(73)

Interest expense

(97)

(88)

(367)

(329)

Income tax recovery

170

111

Preferred dividends

(19)

(18)

(73)

(66)

Other

(2)(3)

(10)

(3)

(16)

Corporate adjusted net loss

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

(73)

(91)

(360)

(356)

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

(2) Other includes realized gains and losses on FX hedges entered into to hedge USD denominated operating unit earnings

exposure.

(3) Includes a realized net loss, pre-tax of $5 million ($4 million after-tax) for the three months ended December 31, 2024

(2023 – $4

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

ended

December 31, 2024 (2023 – $11 million

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

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

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

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

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

December 31, 2024 (2023 – nil).

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

on reversal of a

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

– nil).

LIQUIDITY AND CAPITAL

RESOURCES

The Company generates internally sourced cash from its various regulated and non-regulated energy

investments. Utility customer bases are diversified by both sales volumes and revenues among customer

classes. Emera’s non-regulated businesses provide diverse revenue streams and counterparties to the

business. Circumstances that could affect the Company’s ability to generate cash include changes to

global macro-economic conditions, downturns in markets served by Emera, impact of fuel commodity

price changes on collateral requirements and timely recoveries of fuel and storm costs from customers,

the loss of one or more large customers, regulatory decisions affecting customer rates and the recovery

of regulatory assets, and changes in environmental legislation. Emera’s subsidiaries are generally in a

financial position to contribute cash dividends to Emera provided they do not breach their debt covenants,

where applicable, after giving effect to the dividend payment, and that they maintain their credit metrics.

Emera’s future liquidity and capital needs will be predominately for working capital requirements, ongoing

rate base investment, business acquisitions, greenfield development, dividends and debt servicing.

Emera has an approximate $20 billion capital investment plan over the 2025 through 2029 period and

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

approval.

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

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

operations, debt raised at the utilities, Corporate equity, and proceeds from the pending sale of NMGC to

support normal operations, repayment of existing debt, and capital requirements. Debt raised at certain of

the Company’s utilities is subject to applicable regulatory approvals. Generally, Corporate equity

requirements in support of the Company’s capital investment plan are expected to be funded through

issuance of preferred equity and issuance of common equity through Emera’s DRIP and ATM programs.

Emera has total committed credit facilities with varying maturities that cumulatively provide $2.3 billion

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

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

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

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

Consolidated Cash Flow Highlights

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

31, 2024 and 2023 include:

millions of dollars

2024

2023

$ Change

Cash, cash equivalents and restricted cash, beginning of period

588

332

256

Provided by (used in):

Operating cash flow before changes in working capital

2,194

2,336

(142)

Change in working capital

452

(95)

547

Operating activities

2,646

2,241

405

Investing activities

(2,218)

(2,917)

699

Financing activities

(818)

939

(1,757)

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

cash associated with assets held for sale

(7)

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

for sale, end of period

221

588

(367)

Cash Flow from Operating Activities

Net cash provided by operating activities increased

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

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

Cash from operations before changes in working capital decreased

$142 million for the year ended

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

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

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

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

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

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

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

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

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

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

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

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

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

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

changes in accounts receivable at NSPI.

Cash Flow used in Investing Activities

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

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

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

capital investment in 2024.

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

compared to $2,976 million in 2023. Details of 2024 capital spending by segment are shown below:

●

$1,998 million – Florida Electric Utility (2023 – $1,771 million);

●

$494 million – Canadian Electric Utilities (2023 – $461 million);

●

$626 million – Gas Utilities and Infrastructure (2023 – $673 million);

●

$81 million – Other Electric Utilities (2023 – $63 million); and

●

$7 million – Other (2023 – $8 million).

Cash Flow from Financing Activities

Net cash used in financing activities decreased $1,757 million to $818 million for the year ended

December 31, 2024, compared to net cash provided by financing activities of $939 million in 2023. This

decrease was due to lower issuance of long-term debt at PGS, NSPI, and NMGC, higher repayment of

Emera's committed credit facilities using the LIL transaction proceeds, retirement of long-term debt at

Emera, TEC and NMGC, and higher net repayments under committed credit facilities at NSPI. These

were partially offset by proceeds from the fixed-to-fixed reset rate junior subordinated notes issuance by

EUSHI Finance Inc., lower short-term debt repayments at TEC, and issuance of long-term debt at TEC.

Working Capital

As at December 31, 2024, Emera’s cash and cash equivalents were $196 million (2023 – $567 million)

and Emera’s investment in non-cash working capital was $224 million (2023 – $831 million). Of the cash

and cash equivalents held at December 31, 2024, $185 million was held by Emera’s foreign subsidiaries

(2023 – $482 million). A portion of these funds are invested in countries that have certain exchange

controls, approvals, and processes for repatriation. Such funds are available to fund local operating and

capital requirements unless repatriated.

Contractual Obligations

As at December 31, 2024, contractual commitments for each of the next five years and in aggregate

thereafter consisted of the following:

millions of dollars

2025

2026

2027

2028

2029

Thereafter

Total

Long-term debt principal

(1)

234

3,279

120

651

1,764

13,192

19,240

Interest payment obligations

(2)(3)

884

799

712

705

636

8,210

11,946

Purchased power

(4)

307

277

368

369

4,487

6,176

Transportation

(5)(6)

742

545

544

454

412

3,228

5,925

Capital projects

604

287

915

Fuel, gas supply and storage

(7)

591

711

Pension and post-retirement

obligations

(8)

224

500

Asset retirement obligations

422

436

Other

160

264

717

3,562

5,409

1,938

2,316

3,314

30,027

46,566

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

those related to NMGC. On completion of the sale of

NMGC, all remaining future contractual obligations will be transferred to the buyer.

For further details on the pending transaction,

refer to the "Other Developments" section.

(1) Includes $696 million related to NMGC (2026: $100 million, and $576 million thereafter).

(2) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity.

For debt instruments

with variable rates, interest is calculated for all future periods using the rates in effect at December 31,

2024, including any expected

required payment under associated swap agreements.

(3) Includes $353 million related to NMGC (2025: $26 million, 2026: $26 million, 2027: $23 million, 2028: $23 million,

2029: $23

million, and $232 million thereafter).

(4) Annual requirement to purchase electricity from IPPs or other utilities over varying contract lengths.

(5) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines.

Includes a commitment of

$135 million related to a gas transportation contract between PGS and SeaCoast through 2040.

(6) Includes $86 million related to NMGC (2025: $30 million, 2026: $24 million, 2027: $16 million, 2028: $12 million,

and 2029: $4

million).

(7) Includes $177 million related to NMGC (2025: $109 million, 2026: $52 million, 2027: $13 million, and 2028: $3 million).

(8) Includes the estimated contractual obligation, which is calculated as the current legislatively required contributions

to the

registered funded pension plans, plus the estimated costs of further benefit accruals contracted under NSPI's Collective

Bargaining

Agreement and estimated benefit payments related to other unfunded benefit plans.

NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years

from its January 15, 2018 in-service date. In November 2024, the UARB approved the collection of up to

$197 million from NSPI for the recovery of Maritime Link costs in 2025. The timing and amounts payable

to NSPML for the remainder of the 38-year commitment period are subject to UARB approval.

Emera has committed to obtain certain transmission rights in New Brunswick during summer periods

(April through October, inclusive) for NLH's use, if requested, effective August 15, 2021 and continuing for

50 years. As transmission rights are contracted, the obligations are included within “Other” in the above

table.

Forecasted Consolidated Capital Investments

The 2025 forecasted consolidated capital investments, including AFUDC, are as follows:

millions of dollars

Florida

Electric

Utility

Canadian

Electric

Utilities

Gas Utilities

and

Infrastructure

Other

Electric

Utilities

Other

Total

Generation

358

117

507

New renewable generation

567

648

Electric transmission

169

188

410

Electric distribution

614

140

754

Gas transmission and distribution

481

Facilities, equipment, vehicles, and other

547

620

2,255

485

486

189

3,420

Debt Management

In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to

unsecured committed syndicated revolving and non-revolving bank lines of credit in either CAD or USD

per the table below.

Undrawn

Credit

and

millions of dollars in currency as noted below

Maturity

Facilities

Utilized

Available

In CAD:

Emera – committed revolving credit facility

June 2029

1,300

792

508

NSPI – committed revolving credit facility

June 2029

800

189

611

Emera – non-revolving facility

February 2026

200

In USD:

TEC – committed revolving credit facility

December 2028

800

637

163

TECO Finance – committed revolving credit facility

December 2028

400

184

216

PGS – revolving facility

December 2028

250

138

112

NMGC – revolving credit facility

December 2026

125

Other – committed revolving credit facilities

Various

Emera and its subsidiaries have certain financial and other covenants associated with their debt and

credit facilities. Covenants are tested regularly, and the Company is in compliance with covenant

requirements as at December 31, 2024.

Emera’s significant covenant is listed below:

As at

Financial Covenant

Requirement

December 31, 2024

Emera

Syndicated credit facilities

Debt to capital ratio

Less than or equal to 0.70 to 1

0.55 : 1

Recent significant financing activity for Emera and its subsidiaries are discussed below by segment:

Florida Electric Utilities

On July 12, 2024, TEC repaid a $300 million USD note upon maturity. This note was repaid with

proceeds from commercial paper.

On April 1, 2024, TEC amended its $800 million USD unsecured committed revolving credit facility to

extend the maturity date from December 17, 2026 to December 1, 2028. There were no other changes in

commercial terms from the prior agreement.

On January 30, 2024, TEC issued $500 million USD of senior unsecured bonds that bear interest at 4.90

per cent with a maturity date of March 1, 2029. Proceeds from the issuance were primarily used for the

repayment of short-term borrowings outstanding under the 5-year credit facility.

Canadian Electric Utilities

On June 24, 2024, NSPI amended its unsecured non-revolving credit facility to extend the maturity date

from July 15, 2024 to June 24, 2025 and reduce the facility from $400 million to $300 million. On

December 16, 2024, NSPI repaid the $300 million unsecured non-revolving credit facility using the net

proceeds from the NSPML debt issuance transferred to NSPI as approved by the UARB. For more

information on the FLG, refer to the “Business Overview and Outlook – Canadian Electric Utilities”

section.

On June 24, 2024, NSPI amended its unsecured committed revolving credit facility to extend the maturity

date from December 16, 2027 to June 24, 2029. There were no other material changes in commercial

terms from the prior agreement.

On June 13, 2024, NSPI entered a non-revolving credit facility to finance the Battery Energy Storage

Project. NSPI can request funds under the facility quarterly for amounts related to incurred project costs

up to the total commitment of the lessor of $120 million and 45.06 per cent of the total eligible project

costs over the term of the agreement. The facility will be available until 6 months after completion of the

project, not to exceed May 21, 2027, and matures 20 years following the end of the period. As at

December 31, 2024, NSPI had utilized $19 million from the facility, which bears interest at 2.51 per cent.

Gas Utilities and Infrastructure

On December 10, 2024, Brunswick Pipeline amended its non-revolving loan agreement. The maturity

date was extended to December 2028 and now includes annual principal repayments.

On July 30, 2024, NMGI repaid its $150 million USD fixed rate notes upon maturity.

Other Electric Utilities

On May 2, 2024, BLPC amended its $92 million Barbadian dollar ($46 million USD) loan facility to extend

the maturity date from February 19, 2025 to July 19, 2028. There were no other material changes in

commercial terms from the prior agreement.

Other

On June 24, 2024, Emera amended its unsecured committed revolving credit facility increasing the facility

from $900 million to $1,300 million. Emera also extended the maturity date from June 24, 2027 to June

24, 2029. There were no other material changes in commercial terms from the prior agreement.

On June 24, 2024, Emera repaid its $400 million unsecured non-revolving credit facility set to mature in

August 2024.

On June 18, 2024, EUSHI Finance completed an issuance of $500 million USD fixed-to-fixed reset rate

junior subordinated notes. The notes initially bear interest at a rate of 7.625 per cent, and will reset on

December 15, 2029, and every five years thereafter, to a rate per annum equal to the five-year U.S.

treasury rate plus 3.136 per cent. The notes mature on December 15, 2054. EUSHI Finance, at its option,

may redeem the notes, in whole or in part, 90 days prior to the first interest reset date, and any semi-

annual interest payment date thereafter, at a redemption price equal to the principal amount.

Proceeds from the $500 million USD note issuance discussed above were used to repay an Emera US

Finance LP $300 million USD senior note upon maturity in June 2024, and to repay an NMGI $150 million

USD fixed rate notes upon maturity in July 2024. The remaining proceeds were used for general

corporate purposes.

On June 17, 2024, Emera repaid $200 million on the December 2024 unsecured non-revolving facility,

decreasing the facility from $400 million to $200 million. In December 2024, Emera repaid the $200

million upon maturity.

On April 1, 2024, TECO Finance amended its $400 million USD unsecured committed revolving credit

facility to extend the maturity date from December 17, 2026 to December 1, 2028. There were no other

changes in commercial terms from the prior agreement.

On February 16, 2024, Emera amended its $400 million unsecured non-revolving facility to extend the

maturity date from February 19, 2024 to February 19, 2025. There were no other changes in commercial

terms from the prior agreement. On July 19, 2024, Emera reduced the amount of the facility from $400

million to $200 million. On February 20, 2025, Emera extended the agreement for an additional year to

February 2026 with no other changes in terms. This facility was classified as long-term debt at December

31, 2024.

Credit Ratings

Emera and its subsidiaries have been assigned the following senior unsecured debt ratings:

Fitch

S&P

Moody's

DBRS

Emera

(1)

BBB (Negative)

BBB- (Stable)

Baa3 (Negative)

N/A

TEC

(1)

A (Negative)

BBB+ (Stable)

A3 (Negative)

N/A

PGS

A (Negative)

N/A

NMGC

(2)

BBB+ (Stable)

N/A

NSPI

(1)

N/A

BBB- (Stable)

N/A

BBB (high)(stable)

(1) On January 22, 2025, Standard and Poor’s (“S&P") revised its outlook on Emera and its subsidiaries to stable from negative with

no change to existing ratings.

(2) On May 30, 2024, Fitch Ratings (“Fitch”) revised NMGC’s outlook to stable from negative.

Guaranteed Debt

As of December 31, 2024, the Company had $2.95 billion USD (2023 – $2.75 billion USD) senior

unsecured notes and junior subordinated notes (collectively referred to as the "US Notes”) outstanding.

The US Notes are fully and unconditionally guaranteed, on a joint and several basis, and in the case of

the fixed-to-fixed reset rate junior subordinated notes due 2054 only, on a joint, several and subordinated

basis, by Emera and Emera US Holdings Inc. (“EUSHI”) (in such capacity, the “Guarantor Subsidiaries”).

Emera owns, directly or indirectly, all of the limited and general partnership interests in Emera US

Finance LP.

EUSHI Finance is owned indirectly by Emera through EUSHI.

Other subsidiaries of the Company do not guarantee the US Notes (such subsidiaries are referred to as

the "Non-Guarantor Subsidiaries"); however, Emera has unrestricted access to the assets of consolidated

entities.

In compliance with Rule 13-01 of Regulation S-X, the Company is including summarized financial

information for Emera, EUSHI, Emera US Finance LP and EUSHI Finance (together, the "Obligor

Group"), on a combined basis after transactions and balances between the combined entities have been

eliminated. Investments in and equity earnings of the Non-Guarantor Subsidiaries have been excluded

from the summarized financial information.

The Obligor Group was not determined using geographic, service line or other similar criteria and, as a

result, the summarized financial information includes portions of Emera’s domestic and international

operations. Accordingly, this basis of presentation is not intended to present Emera’s financial condition

or results of operations for any purpose other than to comply with the specific requirements for guarantor

reporting.

Summarized Statement of Income (Loss)

The Company recognized income related to guaranteed debt under the following categories:

For the

Year ended December 31

millions of dollars

2024

2023

Loss from operations

(279)

(62)

Net gains

(1)

442

394

(1) Includes $1,352 million (2023 – $962 million) in interest and dividend income, net, from non-guarantor subsidiaries.

Summarized Balance Sheet

The Company has the following categories on the balance sheet related to guaranteed debt:

As at

December 31

millions of dollars

2024

2023

Current assets

(1)

391

272

Goodwill

5,858

5,871

Other assets

(2)

6,474

6,263

Total assets

(3)

12,723

12,406

Current liabilities

(4)

611

1,264

Long-term liabilities

(5)

13,129

11,956

Total liabilities

13,740

13,220

(1) Includes $217 million (2023 – $178 million) in amounts due from non-guarantor subsidiaries.

(2) Includes $5,937 million (2023 – $5,906 million) in amounts due from non-guarantor subsidiaries.

(3) Excludes investments in non-guarantor subsidiaries. Consolidated Emera total assets are $42,951 million

(2023 – $39,480 million).

(4) Includes $184 million (2023 – $167 million) due to non-guarantor subsidiaries.

(5) Includes $5,980 million (2023 – $5,854 million) due to non-guarantor subsidiaries.

Outstanding Stock Data

Common Stock

millions of

Issued and outstanding:

dollars

Balance, December 31, 2023

284.12

8,462

Issuance of common stock under ATM program

(1)

5.12

261

Issued under the DRIP,

net of discounts

6.10

291

Senior management stock options exercised and Employee Share Purchase Plan

0.60

Balance, December 31, 2024

295.94

9,042

(1) For the year ended December 31, 2024, a total of 5,117,273

common shares were issued under Emera's ATM program

at an

average price of $51.52 per share for gross proceeds of $264 million ($261 million, net of after-tax issuance costs). As at

December 31, 2024, an aggregate gross sales limit of $336 million remained available for issuance under the ATM

program.

As at February 14, 2025, the amount of issued and outstanding common shares was 297.7 million.

If all outstanding stock options were converted as at February 14, 2025, an additional 3.8 million common

shares would be issued and outstanding.

ATM Equity Program

On November 18, 2024, Emera increased the size of the ATM Program to allow the Company to issue up

to $1 billion of common shares from treasury to the public from time to time, at the Company's discretion,

at the prevailing market price. The ATM Program was increased by an amendment dated November 18,

2024 to its prospectus supplement dated November 14, 2023 and an amendment dated November 13,

2024 to its short form base shelf prospectus dated October 3, 2023.

Preferred Stock

As at February 19, 2025, Emera had the following preferred shares issued and outstanding: Series A –

4.9 million; Series B – 1.1 million; Series C – 10.0 million; Series E – 5.0 million; Series F – 8.0 million;

Series H – 12.0 million; Series J – 8.0 million, and Series L – 9.0 million. Emera’s preferred shares do not

have voting rights unless the Company fails to pay, in aggregate, eight quarterly dividends.

On January 8, 2025, Emera announced that it would not redeem the outstanding Series F preferred

shares on February 15, 2025. During the conversion period between January 15, 2025 and January 31,

2025, subject to certain conditions, the holders of Series F shares had the right, at their option, to convert

all or any of their Series F shares, on a one-for-one basis into Cumulative Floating Rate First Preferred

Shares, Series G on February 15, 2025.

On January 16, 2025, Emera announced that the annual fixed dividend per share for Series F shares will

be reset from $1.0505 to $1.4372 for the five-year period from and including February 15, 2025.

On February 6, 2025, Emera announced after having taken into account all conversion notices received

from holders none of the Series F preferred shares were converted to Series G preferred shares.

PENSION FUNDING

For funding purposes, Emera determines required contributions to its largest defined benefit (“DB”)

pension plans based on smoothed asset values. This reduces volatility in the cash funding requirement

as the impact of investment gains and losses are recognized over a multi-year period. Expected cash flow

for DB pension plans is $41 million in 2025 (2024 – $36 million). All pension plan contributions are tax

deductible and will be funded with cash from operations.

Emera’s DB pension plans employ a long-term strategic approach with respect to asset allocation, real

return and risk. The underlying objective is to earn an appropriate return, given the Company’s goal of

preserving capital with an acceptable level of risk for the pension fund investments.

achieve the overall long-term asset allocation, pension assets are managed by external investment

managers per each pension plan’s investment policy and governance framework. The asset allocation

includes investments in the assets of domestic and global equities, domestic and global bonds and short-

term investments. The Company reviews investment manager performance on a regular basis and

adjusts the plans’ asset mixes as needed in accordance with the pension plans’ investment policy.

Emera’s projected contributions to defined contribution pension plans are $56 million for 2025 (2024 –

$51 million).

Defined Benefit Pension Plan Summary

in millions of dollars

Plans by region

TECO Holdings

NSPI

Caribbean

Total

Assets as at December 31, 2024

987

1,495

2,493

Accounting obligation at December 31, 2024

970

1,380

2,367

Accounting expense (income) during fiscal 2024

(11)

(3)

Off-Balance Sheet Arrangements

Defeasance

Upon privatization in 1992, NSPI became responsible for managing a portfolio of defeasance securities

that provide principal and interest streams to match the related defeased debt, which at December 31,

2024 totalled $200 million (2023 – $200 million). The securities are held in trust for an affiliate of the

Province of Nova Scotia. Approximately 66 per cent of the defeasance portfolio consists of investments in

the related debt, eliminating all risk associated with this portion of the portfolio.

Guarantees and Letters of Credit

Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant

guarantees and letters of credit were not included within the Consolidated Balance Sheets as at

December 31, 2024:

TECO Holdings, Inc. (“TECO Holdings”) has a guarantee in connection with SeaCoast’s performance of

obligations under a gas transportation precedent agreement. The guarantee is for a maximum potential

amount of $45 million USD if SeaCoast fails to pay or perform under the contract. The guarantee expires

five years after the gas transportation precedent agreement termination date, which was terminated on

January 1, 2022. The counterparty has the right to require TECO Holdings to provide replacement credit

support either in the form of a substitute guarantee from an affiliate with an investment grade credit rating

or a letter of credit or cash deposit of $27 million USD.

TECO Holdings has a guarantee in connection with SeaCoast’s performance obligations under a firm

service agreement, which expires December 31, 2055, subject to two extension terms at the option of the

counterparty with a final expiration date of December 31, 2071. The guarantee is for a maximum potential

amount of $13 million USD if SeaCoast fails to pay or perform under the firm service agreement. The

counterparty has the right to require TECO Holdings to provide replacement credit support in the form of

either a substitute guarantee from an affiliate with an investment grade credit rating or a letter of credit or

cash deposit of $13 million USD.

Emera has a guarantee of $66 million USD relating to outstanding notes of ECI. This guarantee will

automatically terminate on the date upon which the obligations have been repaid in full.

NSPI has guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated, in the amount

of $104 million USD (2023 – $104 million USD) with terms of varying lengths.

The Company has standby letters of credit and surety bonds in the amount of $105 million USD

(December 31, 2023 – $103 million USD) to third parties that have extended credit to Emera and its

subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed

annually as required.

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

retirement plan. The expiry date of this letter of credit was extended to June 2025. The amount committed

as at December 31, 2024 was $58 million (December 31, 2023 – $56 million).

Emera has provided an indemnity to a counterparty in relation to certain future tax amounts that could

arise from specific future changes in Canadian federal law, subject to certain conditions and limitations.

No such changes in law have been proposed at this time. A reasonable estimate of the potential amount

of future payments that could result from future claims under this indemnity cannot be calculated, but the

risk of having to make any significant payments under this indemnity is considered to be remote.

DIVIDEND PAYOUT

RATIO

Emera has provided annual dividend growth guidance of one to two per cent per year. On September 18,

2024, the Board approved an increase in the annual common share dividend rate to $2.9000 from

$2.8700 per common share. The first quarterly dividend payment at the increased rate was paid on

November 15, 2024.

Emera’s common share dividends paid in 2024 were $2.8775 ($0.7175 in Q1, Q2, and Q3 and $0.7250 in

Q4) per common share and for 2023 were $2.7875 ($0.6900 in Q1, Q2, and Q3 and $0.7175 in Q4) per

common share. This represents a dividend payout ratio of net income of 168 per cent in 2024 (2023 – 78

per cent) and a dividend payout ratio of adjusted net income of 98 per cent in 2024 (2023 – 94 per cent).

TRANSACTIONS WITH RELATED

PARTIES

In the ordinary course of business, Emera provides energy and other services and enters into

transactions with its subsidiaries, associates and other related companies on terms similar to those

offered to non-related parties. Intercompany balances and intercompany transactions have been

eliminated on consolidation, except for the net profit on certain transactions between non-regulated and

regulated entities in accordance with accounting standards for rate-regulated entities. All material

amounts are under normal interest and credit terms.

Significant transactions between Emera and its associated companies are as follows:

●

Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the

Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and

purchased power, totalling a recovery of $324 million for the year ended December 31, 2024 (2023 –

$163 million expense). NSPML is accounted for as an equity investment, and therefore corresponding

earnings related to this revenue are reflected in Income from equity investments.

For further details, refer to the “Business Overview and Outlook – Canadian Electric Utilities –

NSPML” and “Contractual Obligations” sections.

●

Natural gas transportation capacity purchases from M&NP are reported in the Consolidated

Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated,

totalled $

million for the year ended December 31, 2024 (2023

– $14 million).

There were no significant receivables or payables between Emera and its associated companies reported

on Emera’s Consolidated Balance Sheets as at December 31, 2024 and at December 31, 2023.

ENTERPRISE RISK AND RISK MANAGEMENT

Emera has an enterprise-wide risk management process, overseen by its Enterprise Risk Management

Committee (“ERMC”) and monitored by the Board, to ensure risks are appropriately identified, assessed,

monitored and subject to appropriate controls. The Board has a Risk and Sustainability Committee

(“RSC”) to assist the Board in carrying out its risk and sustainability oversight responsibilities. The RSC’s

mandate includes oversight of the Company’s Enterprise Risk Management framework, including the

identification, assessment, monitoring and management of enterprise risks.

The significant business risks to Emera are described below, many of which are beyond the Company’s

control, and could have a material adverse effect on Emera or its subsidiaries, or their business

operations, liquidity or access to or cost of capital, financial position, prospects, and/or results of

operations (herein considered a “Material Adverse Effect”). The nature of risk is such that no such list is

comprehensive, and the actual effect of any of the risks discussed could be materially different from what

is described below. Additionally,

other risks not presently known may arise, risks not currently considered

material may become material in the future, or two or more risks which are not themselves material, could

together be material.

Regulatory and Political Risk

The Company’s rate-regulated subsidiaries and certain investments are subject to complex legislative

and regulatory frameworks that cover material aspects of their businesses. These frameworks influence

key factors such as rates and cost structures, revenue requirements, allowed ROEs, capital structures,

rate base and capital investments, and the recovery of purchased electricity and fuel costs and other

costs. Regulators also review the prudency of costs and make other decisions that can impact customer

rates and the reliability of service. Emera’s cost-of-service utilities must obtain regulatory approvals for

material aspects of their businesses, including changing or adding rates and/or riders. Such approvals

often require public hearing proceedings involving numerous stakeholders, and there is no assurance in

the outcomes or impact of any regulatory process or decision.

If Emera is unable to recover in a timely manner a material amount of costs or a return on invested capital

through regulatory mechanisms or otherwise, is disallowed the recovery of certain costs, is subject to

regulatory penalties, is not permitted to make certain capital investments, or is not permitted to invest in or

divest certain utility assets, it could result in a Material Adverse Effect, including valuation impairments.

Regulatory lag, the time between the incurrence of costs and the granting of the rates to recover those

costs by regulators, may also result in a Material Adverse Effect.

Aspects of the acquisition, ownership, operations, siting, planning, construction, and decommissioning of

electric generation, storage, transmission and distribution facilities and natural gas transportation and

distribution systems are also subject to regulatory processes and approvals of regulators, government

departments and agencies, and other third parties. The failure to obtain, maintain, and renew such

approvals or significant changes in the terms and conditions thereof could have a Material Adverse Effect.

The regulatory framework, process and regulatory decisions may also be adversely affected by changes

in government, shifts in government or public policy, legislative changes, regulatory decisions, geopolitical

changes, changes in the economic environment, or other factors. Government interference in the

regulatory process or regulatory decisions can undermine regulatory stability, predictability,

and

independence. Any such changes could have a Material Adverse Effect.

Change in Law Risk

The Company is also exposed to changes in the political environment and leadership, changes in law or

regulations, changes to governmental policies, trade disputes, and the imposition of tariffs, any of which

may impact the Company’s businesses, the markets for energy and inputs thereto, or general economic

conditions, and which may result in a Material Adverse Effect. This may include initiatives regarding

deregulation or restructuring of the energy industry, which may result in increased competition, and

increased or unrecovered costs. State and local policies in some US jurisdictions have sought to prevent

or limit the ability of utilities to provide customers the choice to use natural gas while in other jurisdictions

policies have been adopted to prevent limitations on the use of natural gas.

Emera cannot predict future legislative, policy, or regulatory changes, whether caused by economic,

political or other factors, or the resulting operating or compliance costs or other impacts. It may be difficult

for Emera to respond in an effective and timely manner to such future legislative, policy or regulatory

changes.

Environmental Legislation

Emera is subject to extensive regulation by federal, provincial, state, regional and local authorities

regarding environmental matters, primarily related to its utility operations. This includes laws, regulations

and policies relating to GHG emissions, renewable energy standards, climate change, air quality, water

quality and usage, waste management, wastewater discharges, soil quality, aquatic and terrestrial

habitats, hazardous waste, health, endangered species, and wildlife mortality.

In some jurisdictions where Emera operates, government legislation and policy has included timelines for

mandated shutdowns of coal-fired generating facilities, has required a certain percentage of electricity be

generated from renewables, carbon pricing, emissions limits and cap and trade mechanisms. Over the

medium and long terms, these could potentially lead to a significant portion of hydrocarbon infrastructure

assets being subject to additional regulation and limitations in respect of GHG emissions and operations.

Both the Government of Nova Scotia and the Government of Canada have enacted or introduced

legislation that includes goals of net-zero GHG emissions by 2050. The Province of Nova Scotia has

established targets with respect to the percentage of renewable energy in NSPI’s generation mix and

reductions in GHG emissions, as well as the goal to phase out coal-fired electricity generation by 2030.

The Government of Canada has also enacted regulations imposing emissions standards on coal-fired

generation that would effectively require the decommissioning of such facilities. While Nova Scotia is

exempted from such regulations through 2029, there is no guarantee that such exemption will continue

into the future. Failure to meet such goals by 2030 or comply with applicable legislation or regulation

could result in a Material Adverse Effect.

Per- and polyfluoroalkyl substances (“PFAS”) are man-made chemicals that are widely used in consumer

products and can persist and bio-accumulate in the environment. The Company does not manufacture

PFAS but because these emerging contaminants of concern are so ubiquitous in products and the

environment, it may impact Emera’s operations. Changes in environmental laws and regulations related

to PFAS could result in new costs or obligations for investigation and cleanup and change the Company’s

strategy for land acquisition for projects such as solar generation and could result in a Material Adverse

Effect.

These and new or revised environmental laws, regulations, policies, or interpretations of those laws,

regulations or policies could result in a Material Adverse Effect by, among other things, preventing or

delaying the development of energy infrastructure projects, restricting the use or output of certain

facilities, requiring the early retirement of certain generation facilities that could result in stranded costs,

limiting the availability or use of certain fuels required for the production of electricity, requiring additional

pollution control equipment, curtailing sales of natural gas to new customers, which could reduce future

customer growth in Emera’s natural gas businesses, changing the nature and timing of capital

investments, requiring significant capital investments, imposing operating or other costs associated with

compliance including carbon taxes or emissions allowances, or by limiting or eliminating certain

operations or rendering such operations uneconomical.

Impacts could be more significant in the future as

the result of new or revised laws or requirements or stricter or more expansive application of existing

environmental laws, regulations and policies. Failure to recover environmental costs in a timely manner

through rates may also result in a Material Adverse Effect.

In addition to imposing continuing compliance obligations, there are permit requirements, laws and

regulations authorizing the imposition of penalties for non-compliance, exposing Emera to legal or

regulatory proceedings, disputes, civil fines, injunctive relief, criminal penalties and other sanctions, which

could result in a Material Adverse Effect.

Weather Risk

A Material Adverse Effect may arise from weather seasonal variations impacting energy consumption, as

well as severe weather events, changing air temperatures, wildfires and other severe weather conditions

that are expected to become more frequent and intense as a result of climate change. Refer to “Climate

Change Risk”.

The temperature, seasonal variations, and other weather conditions significantly influence the availability

and demand for electricity and natural gas by customers, the price of energy commodities, such as fuel

used by the Company’s utilities, and the production of electricity at power generation facilities. For

example, NSPI could see lower sales in winter months if temperatures are warmer than expected.

Severe weather events or conditions such as hurricanes, floods, storm surge, tornadoes, droughts, fires,

extreme temperatures, snow or ice storms, and other natural disasters create a risk of physical damage to

the Company’s assets and a risk of extended service outages or fuel supply disruptions.

For example,

high winds can cause widespread damage to transmission and distribution infrastructure, solar

generation, and wind-powered generation. Substantially all of the Company’s fossil fueled generation

assets are located at or near coastal sites and, as such, are exposed to the separate and combined

effects of rising sea levels and increasing storm intensity, including storm surges and flooding.

Severe weather events or conditions could reduce revenues and require the Company to incur additional

costs, such as repair and replacement costs, costs of replacement power and fuel, increased insurance

costs, and the need to access additional financing sources. These could result in a Material Adverse

Effect if not resolved or mitigated in a timely and efficient manner through insurance or regulatory cost

recovery. This risk to transmission and distribution facilities is typically not insured, and as such the

restoration cost is generally recovered through regulatory processes, either in advance through reserves,

or after the fact through the establishment of regulatory assets. Recovery is not assured, is subject to

prudency review, and may be subject to delay resulting in increased debt and debt servicing costs.

Severe weather events or other catastrophic natural disasters could also result in long-term reductions in

demand for electricity or natural gas or the slowing of customer growth in one or more of the Company’s

service territories, which could have a Material Adverse Effect. The impact of extreme weather events

would be amplified if the same events affect multiple utilities in the Company’s portfolio.

High winds and lack of precipitation also increase the risk of wildfires resulting from the Company’s

infrastructure or for which the Company may otherwise have responsibility. If it is found to be responsible

for such a fire, the Company could suffer material costs, losses and damages, all or some of which may

not be recoverable through insurance, legal, regulatory cost recovery or other processes. If not recovered

through these means or if recovery is delayed, they could result in a Material Adverse Effect. Resulting

costs could include fire suppression costs, regeneration, timber value, increased insurance costs and

costs arising from damages and losses incurred by third parties.

The Company purchases power from third-party owned hydroelectricity sources and operates

hydroelectric generation in certain of its markets. Such generation depends on availability of water and

the hydrological profile of water sources. Changes in precipitation patterns, water temperatures and air

temperatures could adversely affect the availability of water and consequently the amount of electricity

that may be produced from such facilities.

Climate Change Risk

Physical Risk:

Climate change may negatively impact the Company’s operations as a result of increased frequency and

intensity of weather events and related physical risks, any of which could result in a Material Adverse

Effect (for more information refer to “Weather Risk” and “System Operating and Maintenance Risks”). An

increase in physical risk associated with climate change can also adversely impact the cost and

availability of insurance, insurance deductibles and self-retention, as well as credit ratings, which could

affect credit risk spreads on new long-term debt and credit facilities, as well as their availability (refer to

“Liquidity and Capital Markets Risk”).

Transition Risk:

As government policy and the economy transition toward decarbonization in many jurisdictions, the

Company is exposed to risks arising from policy, legal, technology,

and market changes, which could

result in a Material Adverse Effect. The energy transition will require the Company to address changes to

environmental policies, laws and regulations which are being proposed and adopted in many jurisdictions

in response to concerns regarding the effects or impacts of climate change (refer to “Environmental

Legislation”). The pace of such new initiatives is expected to accelerate in some jurisdictions.

The Company will be required to manage the impacts of these changes on customer demand and rates,

while integrating increased amounts of intermittent renewable energy sources and new technologies,

implementing and making the investments required to meet new resiliency and security standards, and

adapting the Company’s infrastructure and generating capacity to meet changing customer demands and

usage patterns. The energy transition and the ability of the Company to achieve mandated climate related

targets and goals will require significant capital investment, effective engagement with policymakers,

regulators and stakeholders, and depend upon many factors which are outside of the Company’s direct

control. Depending on the regulatory response to government legislation and regulations, the Company

may be exposed to the risk of reduced recovery through rates in respect of the affected assets.

Given concerns regarding carbon-emitting generation, assets and businesses may, over time, become

difficult or uneconomic to insure in commercial insurance markets. Some insurance companies have

begun to limit their exposure to coal-fired electricity generation and are evaluating the medium and long-

term impacts of climate change which may result in less insurance capacity, more restrictive coverage

and increased premiums. The Company could also face litigation or regulatory action related to

environmental harms from GHG emissions or failure to substantiate certain environmental claims.

The failure to effectively respond to climate change transition risks could adversely affect the Company’s

ability to deliver safe, reliable, and cost-effective service, the Company’s reputation with stakeholders, its

ability to operate and grow, and the Company’s access to, and cost of, capital, each of which could result

in a Material Adverse Effect.

Cybersecurity Risk

Emera is exposed to potential risks related to cyberattacks, data breaches, cyber-extortion, and

unauthorized access that could result in a Material Adverse Effect. The Company relies on IT systems,

cloud infrastructure, third-party service providers and the diligence of its team members to effectively

manage and safely operate its assets. This includes controls for interconnected systems of generation,

distribution and transmission as well as financial, billing and other enterprise systems. As the Company

operates critical energy infrastructure, it may be at greater risk of cyberattacks, which could include those

from nation-state cyber threat actors. Major emerging and ongoing global conflicts may also elevate this

risk, by increasing the sophistication, magnitude, and frequency of cyberattacks.

Cyberattacks can reach the Company’s assets and information via their interfaces with third parties or the

public internet and gain access to critical and non-critical infrastructures. Cyberattacks can also occur via

personnel with access to critical assets or trusted networks. Methods used to attack critical assets could

include generic or energy-sector-specific malware delivered via network transfer, removable media,

attachments, links in e-mails or other communications, or social engineering. The methods used by

attackers are continuously evolving and can be difficult to predict and detect and may become more

sophisticated, frequent, severe, and difficult to stop to the extent that attackers are able to leverage

evolving artificial intelligence models or tools.

Despite security measures in place, the Company’s systems, assets and information could experience

security breaches that could cause system failures, disrupt energy supply and delivery, business

operations, or adversely affect safety. Such breaches could compromise customer, employee-related or

other information systems and could result in loss of service to customers, unavailability of critical assets,

safety issues, compromise billing and customer-facing information, such as outage maps, disrupt internal

control and financial processes, or result in the release, loss, corruption, destruction, and/or misuse of

critical, sensitive, confidential or proprietary information, intellectual property, or personal information of

customers or employees. These breaches could also delay delivery or result in contamination or

degradation of hydrocarbon products the Company transports, stores or distributes.

Cyberattacks or unauthorized access may cause lost revenues, costs, losses, regulatory penalties and

third-party damages all, or some of which may not be recoverable through insurance, legal, regulatory

cost recovery or other processes. Resulting costs could include, amongst others, response, recovery and

remediation costs, increased protection or insurance costs and costs arising from damages and losses

incurred by third parties. This could result in a Material Adverse Effect and there is no assurance that

cyberattacks or other security breaches can be adequately addressed in a timely manner.

The Company seeks to manage these risks by aligning to a common set of cybersecurity standards and

policies derived, in part, on the National Institute of Standards and Technology’s Cyber Security

Framework, periodic security testing, program maturity objectives, cybersecurity incident readiness

program, and employee communication and training. With respect to certain of its assets, the Company is

required to comply with rules and standards relating to cybersecurity and IT including, but not limited to,

those mandated by bodies such as the North American Electric Reliability Corporation, Northeast Power

Coordinating Council, and the United States Department of Homeland Security. The status of key

elements of the Company’s cybersecurity program is reported to the RSC. The Board oversees risk and

mitigation plans in relation to cybersecurity risks and receives a quarterly update in a risk dashboard at

each regularly scheduled Board meeting.

Energy Consumption Risk

Emera’s rate-regulated utilities are affected by demand for energy based on changing customer patterns

due to fluctuations in a number of factors including general economic conditions, weather events,

customers’ focus on energy efficiency, changes in rates, and advancements in new technologies such as

rooftop solar, electric vehicles, data centers, and battery storage. Government policies promoting energy

efficiency, distributed generation, and new technology developments that enable those policies, have the

potential to impact how electricity enters the system and how it is bought and sold. In addition, increases

in distributed generation may impact demand resulting in lower load and revenues. These changes could

negatively impact Emera’s operations, rate base, net earnings, and cash flows and result in a Material

Adverse Effect.

Foreign Exchange Risk

The Company is exposed to foreign currency exchange rate changes. Emera operates internationally,

with a significant amount of the Company’s net income earned outside of Canada. As such, Emera is

exposed to movements in exchange rates between the CAD and, particularly, the USD, which could

positively or adversely affect results.

Emera manages currency risks through matching US denominated debt to finance its US operations and

may use foreign currency derivative instruments to hedge specific transactions and earnings exposure.

The Company may enter FX forward and swap contracts to limit exposure on certain foreign currency

transactions such as fuel purchases, revenue streams and capital expenditures, and on net income

earned outside of Canada. The regulatory framework for the Company’s rate-regulated subsidiaries

permits the recovery of prudently incurred costs, including FX.

The Company does not utilize derivative financial instruments for foreign currency trading or speculative

purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on

net investments in foreign subsidiaries do not impact net income as they are reported in Accumulated

Other Comprehensive Income (Loss) ("AOCI”).

Liquidity and Capital Markets Risk

Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial

obligations. Emera’s access to capital and cost of borrowing is subject to several risk factors, including

financial market conditions, market disruptions and ratings assigned by various market analysts, including

credit rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or

cause the Company to issue securities with less than preferred terms and conditions. Emera’s growth

plan requires significant capital investments in PP&E and the risk associated with changes in interest

rates could have an adverse effect on the cost of financing. The Company’s future access to capital and

cost of borrowing may be impacted by various market disruptions. The inability to access cost-effective

capital could have a material impact on Emera’s ability to fund its growth plan.

Emera is subject to financial risk associated with changes in its credit ratings. There are a number of

factors that rating agencies evaluate to determine credit ratings, including the Company’s business, its

regulatory framework and legislative environment, political interference in the regulatory process, the

ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to

climate change-related impacts, including increased frequency and severity of hurricanes and other

severe weather events. A decrease in a credit rating could result in higher interest rates in future

financings, increased borrowing costs under certain existing credit facilities, limit access to the

commercial paper market, or limit the availability of adequate credit support for subsidiary operations. For

certain derivative instruments, if the credit ratings of the Company were reduced below investment grade,

the full value of the net liability of these positions could be required to be posted as collateral.

The Company has exposure to its own common share price through the issuance of various forms of

stock-based compensation, which affect earnings through revaluation of the outstanding units every

period. The Company uses equity derivatives to reduce the earnings volatility derived from stock-based

compensation.

General Economic Risk

The Company has exposure to the macro-economic conditions in North America and in other geographic

regions in which Emera operates. Like most utilities, economic factors such as consumer income,

employment and housing affect demand for electricity and natural gas and, in turn, the Company’s

financial results. Adverse changes in general economic conditions and inflation may impact the ability of

customers to afford rate increases arising from increases to fuel, operating, capital, environmental

compliance, and other costs, and therefore could have a Material Adverse Effect. This may also result in

higher credit and counterparty risk, adverse shifts in government policy and legislation, and/or increased

risk to full and timely recovery of costs and regulatory assets.

Interest Rate Risk:

Emera utilizes a combination of fixed and floating rate debt financing for operations and capital

expenditures, resulting in an exposure to interest rate risk.

For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt

costs are recovered from customers. Regulatory ROE will generally follow the direction of interest rates,

such that regulatory ROEs are likely to fall in times of reducing interest rates and rise in times of

increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory

process. Rising interest rates may also negatively affect the economic viability of project development

and acquisition initiatives.

Interest rates could also be impacted by changes in credit ratings. For more information, refer to “Liquidity

and Capital Markets Risk”.

As with most other utilities and other similar yield-returning investments, Emera’s share price may be

affected by changes in interest rates and could underperform the market in an environment of rising

interest rates.

Inflation Risk:

The Company may be exposed to changes in inflation that may result in increased operating and

maintenance costs, capital investment, and fuel costs compared to the revenues provided by customer

rates.

Public Health Crisis Risk

An outbreak of infectious disease, a pandemic or other public health threats, or a fear of any of the

foregoing, could result in a Material Adverse Effect to Emera and its subsidiaries. This could include

causing operating, supply chain and project development delays and disruptions, labour shortages and

shutdowns (including as a result of government regulation and prevention measures), which could have a

negative impact on the Company’s operations.

Any adverse changes in general economic and market conditions arising as a result of a public health

threat could negatively impact demand for electricity and natural gas, revenue, operating costs, timing

and extent of capital investments, capital market activities, and counterparty risk; which could result in a

Material Adverse Effect.

Health and Safety

The Company’s operations inherently involve risk to the health and safety of employees, contractors and

members of the public. Personal injury or loss of life resulting from failure to implement or observe

appropriate health and safety procedures or comply with health and safety laws and regulations could

result in adverse operational, reputational, legal, regulatory, or financial impacts, any of which could have

a Material Adverse Effect.

Project Development and Land Use Rights Risk

The Company’s capital plan includes significant investment in generation, infrastructure modernization,

and customer-focused technologies. Any projects planned or currently in construction, particularly

significant capital projects, may be subject to risks that could result in a Material Adverse Effect including,

but not limited to, impact on costs from schedule delays, increased demand for renewable energy inputs,

risk of cost overruns, ensuring compliance with operating and environmental requirements and other

events within or beyond the Company’s control. The Company’s projects may also require approvals and

permits at the federal, provincial, state, regional and local levels. There is no assurance that Emera will

be able to obtain the necessary project approvals or applicable permits or receive regulatory approval to

recover the costs in rates.

Some of the Company’s assets are located on land owned by third parties, including Indigenous Peoples,

and may be subject to land claims. Present or future assets may be located on lands that have been used

for traditional purposes and therefore subject to specific consultations, consents, or conditions for

development or operation. If the Company’s rights to locate and operate its assets on any such lands are

subject to expiry or become invalid, it may incur material costs to renew rights or obtain such rights. If

reasonable terms for land-use rights cannot be negotiated, the Company may incur significant costs to

remove and relocate its assets and restore the land. Additional costs incurred could cause projects to be

uneconomical to proceed with.

Counterparty Risk

Emera is exposed to risk related to its reliance on certain key partners, suppliers, and customers, any of

which may endure financial challenges resulting from commodity price and market volatility, economic

instability or adversity, adverse political or regulatory changes and other causes which may cause or

contribute to such parties’ insolvency, bankruptcy,

restructuring or default on their contractual obligations

to Emera.

Emera is also exposed to potential losses related to amounts receivable from customers,

energy marketing collateral deposits and derivative assets due to a counterparty’s non-performance

under an agreement.

There is no assurance that management strategies will be effective, and significant counterparty defaults

could result in a Material Adverse Effect.

Supply Chain Risk

Emera’s ability to meet customer energy requirements, respond to storm-related disruptions and execute

on the capital investment program in a cost-effective and timely manner are dependent on maintaining an

efficient supply chain. Domestic and global supply chain issues may delay the delivery, increase the cost,

or result in shortages of certain materials, fuel, equipment and other resources that are critical to the

Company’s operations. These disruptions may be further exacerbated by inflationary pressures, labour

shortages, more frequent and severe weather events, government incentives increasing demand for

clean energy projects, changes in carbon-related costs, policies and regulations, and the impact of

international conflicts. In addition, global supply chains and the financial condition and results of the

business could be Materially Adversely Affected by the imposition of custom duties or other tariffs, or an

increase in trade restrictions in the future. Failure to eliminate or manage supply chain constraints may

impact the availability and cost of items and labour that are necessary to support operations and capital

investment and could have a Material Adverse Effect.

Fuel Supply Disruptions:

Emera’s electric and natural gas utilities are also exposed to the risk of fuel supply chain disruptions, both

within and outside their service territories, which may be caused by severe weather or natural disasters.

This may also be caused by damage to, operational issues with, terrorist or cyberattacks on, third party

fuel production, storage, pipeline, and distribution facilities. Significant unanticipated fuel supply

disruptions could result in increased exposure to commodity price risk for Emera’s regulated electric and

gas utilities and Emera Energy, and these could have a Material Adverse Effect.

Commodity Price Risk

The Company’s utility fuel supply and purchase of other commodities is subject to commodity price risk.

In addition, Emera Energy is subject to commodity price risk through its portfolio of commodity contracts

and arrangements.

Regulated Utilities:

The Company’s utility fuel supply is exposed to broader global market conditions, which may include

impacts on delivery reliability and price, despite contracted terms. Supply and demand dynamics in fuel

markets can be affected by a wide range of factors which are difficult to predict and may change rapidly,

including but not limited to, currency fluctuations, changes in global economic conditions, natural

disasters, transportation or production disruptions, and geo-political risks, such as political instability,

conflicts, changes to international trade agreements, tariffs, trade sanctions or embargos.

Prolonged and substantial increases in fuel prices could result in decreased rate affordability, increased

risk of recovery of costs or regulatory assets, and/or negative impacts on customer consumption patterns

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

Emera Energy Marketing and Trading:

The majority of Emera Energy’s portfolio of electricity and gas marketing and trading contracts and, in

particular, its natural gas asset management arrangements, are contracted on a back-to-back basis,

avoiding any material long or short commodity positions. However, the portfolio is subject to commodity

price risk, particularly with respect to basis point differentials between relevant markets in the event of an

operational issue, imposition of tariffs, or counterparty default. Changes in commodity prices can also

result in increased collateral requirements associated with physical contracts and financial hedges,

resulting in higher liquidity requirements and increased costs to the business.

Future Employee Benefit Plan Performance and Funding Risk

Emera subsidiaries have both defined benefit and defined contribution employee pension plans that cover

employees and retirees. All defined benefit plans are closed to new entrants, except for the TECO

Holdings Group Retirement Plan and the Grand Bahama Power Company Limited Union Employees’

Pension Plan. The cost of providing these benefit plans varies depending on plan provisions, interest

rates, inflation, investment performance and actuarial assumptions concerning the future. Actuarial

assumptions include earnings on plan assets, discount rates (interest rates used to determine funding

levels, contributions to the plans and the pension and post-retirement liabilities) and expectations around

future salary growth, inflation and mortality. The three largest drivers of cost are investment performance,

interest rates and inflation, which are affected by global financial and capital markets. Depending on

future interest rates and future inflation and actual versus expected investment performance, Emera could

be required to make larger contributions in the future to fund these plans, which could have a Material

Adverse Effect.

Labour Risk

Emera’s ability to deliver service to its customers and to execute its growth plan depends on attracting,

developing and retaining a skilled workforce. Utilities are faced with demographic challenges related to

trades, technical staff and engineers with an increasing number of employees expected to retire over the

next several years. Failure to attract, develop and retain an appropriately qualified workforce could have a

Material Adverse Effect.

Approximately 30 per cent of Emera’s labour force is represented by unions and subject to collective

labour agreements. The inability to maintain or negotiate future agreements on acceptable terms could

result in higher labour costs and work disruptions, which could adversely affect service to customers and

have a Material Adverse Effect.

IT Risk

Emera relies on various IT systems to manage operations, including increasing reliance on IT solutions

operated by third parties, such as software as a service and third-party cloud hosting. This subjects

Emera to inherent costs and risks associated with maintaining, upgrading, replacing and changing these

systems. This includes impairment of its IT, potential disruption of internal control systems, substantial

capital expenditures, demands on management time and other risks of delays, difficulties in upgrading

existing systems, transitioning to new systems or integrating new systems into its current systems.

Emera’s digital transformation strategy, including investment in infrastructure modernization and customer

focused technologies, is driving increased investment in IT solutions, resulting in increased project risks

associated with the implementation of these solutions.

Income Tax Risk

The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in

Canada, the US and the Caribbean and any such changes could have a Material Adverse Effect. The

value of Emera’s existing deferred income tax assets and liabilities are determined by existing tax laws

and could be negatively impacted by changes in laws.

System Operating and Maintenance Risks

The safe and reliable operation of electric generation and electric and natural gas transmission and

distribution systems is critical to Emera’s operations. There are a variety of hazards and operational risks

inherent in operating electric utilities and natural gas transmission and distribution pipelines. Electric

generation, transmission and distribution operations can be impacted by risks such as mechanical

failures, supply chain issues impacting timely access to critical equipment, activities of third parties,

terrorism, cyberattacks, human error, damage to facilities, and infrastructure caused by hurricanes,

storms, falling trees, lightning strikes, floods, fires and other natural disasters. Natural gas pipeline

operations can also be impacted by risks such as leaks, explosions, mechanical failures, activities of third

parties, terrorism, cyberattacks, and damage to the pipeline facilities and equipment caused by

hurricanes, storms, floods, fires and other natural disasters. Electric utility and natural gas transmission

and distribution pipeline operation interruption could negatively affect customer and public confidence,

and public safety and have a Material Adverse Effect.

Insurance, warranties, or recovery through regulatory mechanisms may not cover any or all these losses,

which could have a Material Adverse Effect.

Uninsured Risk

Emera and its subsidiaries maintain insurance to cover accidental loss suffered to its facilities and to

provide indemnity in the event of liability to third parties. A significant portion of Emera’s electric utilities’

transmission and distribution assets and its gas utilities’ distribution assets are not insured, as is

customary in the industry, as the cost of coverage is prohibitive. In addition, Emera accepts deductibles

and self-insured retentions under its various insurance policies. Insurance is subject to coverage limits as

well as time sensitive claims discovery and reporting provisions and there can be no assurance that the

types of liabilities or losses that may be incurred will be covered by insurance.

The occurrence of significant uninsured claims, claims in excess of the insurance coverage limits, or

claims that fall within a significant self-insured retention could have a Material Adverse Effect, if regulatory

recovery is not available.

RISK MANAGEMENT INCLUDING FINANCIAL

INSTRUMENTS

The Company manages exposure to normal operating and market risks relating to commodity prices, FX,

interest rates and share prices through contractual protections with counterparties where practicable, and

by using financial instruments consisting mainly of FX forwards and swaps, interest rate options and

swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the

Company has contracts for the physical purchase and sale of natural gas. These physical and financial

contracts are classified as HFT. Collectively,

these contracts and financial instruments are considered

derivatives.

The Company recognizes the FV of all its derivatives on its balance sheet, except for non-financial

derivatives that meet the normal purchases and normal sales (“NPNS”) exception. Physical contracts that

meet the NPNS exception are not recognized on the balance sheet; these contracts are recognized in

income when they settle. A physical contract generally qualifies for the NPNS exception if the transaction

is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources

within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the

commodity, and the Company deems the counterparty creditworthy.

The Company continually assesses

contracts designated under the NPNS exception and will discontinue the treatment of these contracts

under this exemption if the criteria are no longer met.

Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be

proven to effectively hedge identified risk both at the inception and over the term of the instrument.

Specifically, for cash flow hedges, change in the FV of derivatives is deferred to AOCI and recognized in

income in the same period the related hedged item is realized. Where documentation or effectiveness

requirements are not met, the derivatives are recognized at FV with any changes in FV value recognized

in net income in the reporting period, unless deferred as a result of regulatory accounting.

Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for

which the NPNS exception has not been taken, are subject to regulatory accounting treatment. The

change in FV of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized

in the hedged item when the hedged item is settled. Management believes any gains or losses resulting

from settlement of these derivatives related to fuel for generation and purchased power will be refunded

to or collected from customers in future rates. TEC and PGS have no derivatives related to hedging.

Derivatives that do not meet any of the above criteria are designated as HFT, with changes in FV

normally recorded in net income of the period. The Company has not elected to designate any derivatives

to be included in the HFT category where another accounting treatment would apply.

Derivative Assets and Liabilities Recognized on the Balance Sheet

As at

December 31

millions of dollars

2024

2023

Regulatory Deferral:

Derivative instrument assets

(1)

Derivative instrument liabilities

(2)

(40)

(76)

Regulatory assets

(1)

Regulatory liabilities

(2)

(44)

(17)

Net asset

HFT Derivatives:

Derivative instrument assets

(1)

122

202

Derivatives instruments liabilities

(2)

(542)

(421)

Net liability

(420)

(219)

Other Derivatives:

Derivative instrument assets

(1)

Derivatives instruments liabilities

(2)

(36)

(7)

Net asset (liability)

(36)

(1) Current, other and assets held for sale.

(2) Current, long-term and liabilities associated with assets held for sale.

Realized and Unrealized Gains (Losses) Recognized in Net Income

For the

Year ended December 31

millions of dollars

2024

2023

Regulatory Deferral:

Regulated fuel for generation and purchased power

(1)

(44)

HFT Derivatives:

Non-regulated operating revenues

207

1,037

Other Derivatives:

OM&G

(9)

Other income, net

(56)

Net gains (losses)

(42)

Total net gains

121

1,107

(1) Realized gains (losses) on derivative instruments settled and consumed in the period, hedging relationships that have

been

terminated or the hedged transaction is no longer probable. Realized gains (losses) recorded in inventory will be recognized

“Regulated fuel for generation and purchased power” when the hedged item is consumed.

As of December 31, 2024, the unrealized gain in AOCI was $12 million, after-tax (December 31, 2023 –

$14 million, after-tax). For the year ended December 31, 2024, unrealized gains of $2 million (2023 – $2

million) have been reclassified from AOCI into interest expense.

DISCLOSURE AND INTERNAL CONTROLS

Management is responsible for establishing and maintaining adequate disclosure controls and

procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National

Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”). The

Company’s internal control framework is based on criteria published in the Internal Control Integrated

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

Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer,

evaluated the design and effectiveness of the Company’s DC&P and ICFR as at December 31, 2024 to

provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.

Management recognizes the inherent limitations in internal control systems, no matter how well designed.

Control systems determined to be appropriately designed can only provide reasonable assurance with

respect to the reliability of financial reporting and may not prevent or detect all misstatements.

There were no changes in the Company’s ICFR, during the year ended December 31, 2024, that have

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

financial reporting.

CRITICAL ACCOUNTING ESTIMATES

The preparation of consolidated financial statements in accordance with USGAAP requires management

to make estimates and assumptions. These may affect reported amounts of assets and liabilities at the

date of the financial statements and reported amounts of revenues and expenses during the reporting

periods. Significant areas requiring use of management estimates relate to rate-regulated assets and

liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled

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

income taxes, asset retirement obligations (“ARO”), and valuation of financial instruments. Management

evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and

expected conditions and assumptions believed to be reasonable at the time the assumption is made, with

any adjustments recognized in income in the year they arise.

Rate Regulation

The rate-regulated accounting policies of Emera’s rate-regulated subsidiaries and regulated equity

investments are subject to examination and approval by their respective regulators and may differ from

the accounting policies of non-rate-regulated companies. Differences occur when regulators render their

decisions on rate applications or other matters, and generally involve a difference in the timing of revenue

and expense recognition. The accounting for these items is based on expectations of the future actions of

the regulators. Assumptions and judgments used by regulatory authorities continue to have an impact on

recovery of costs, rates earned on invested capital, and the timing and amount of assets to be recovered.

Application of regulatory accounting guidance is a critical accounting policy as a change in these

assumptions may result in a material impact on reported assets, liabilities and the results of operations.

As at December 31, 2024, the Company had recorded $3,427 million (2023 – $3,105 million) of regulatory

assets and $1,880 million (2023 – $1,772 million) of regulatory liabilities.

Accumulated Reserve – Cost of Removal

TEC, PGS, NMGC and NSPI recognize non-ARO costs of removal (“COR”) as regulatory liabilities. The

non-ARO COR represent estimated funds received from customers through depreciation rates to cover

future COR of PP&E upon retirement that are not legally required. The companies accrue for COR over

the life of the related assets based on depreciation studies approved by their respective regulators. Costs

are estimated based on historical experience and future expectations, including expected timing and

estimated future cash outlays. As at December 31, 2024, the balance of the Accumulated reserve – COR

within regulatory liabilities was $733 million (2023 – $849 million).

Pension and Other Post-Retirement Employee Benefits

The Company provides post-retirement benefits to employees, including defined benefit pension plans.

The cost of providing these benefits is dependent upon many factors that result from actual plan

experience and assumptions of future expectations.

The accounting related to employee post-retirement benefits is a critical accounting estimate. Changes in

the estimated benefit obligation, affected by employee demographics - including age, compensation

levels, employment periods, contribution levels and earnings - could have a material impact on reported

assets, liabilities, accumulated other comprehensive income and results of operations. Changes in key

actuarial assumptions, including anticipated rates of return on plan assets and discount rates used in

determining the accrued benefit obligation and benefit costs, could change annual funding requirements.

This could have a significant impact on the Company’s annual earnings and cash requirements.

Pension plan assets are comprised primarily of equity and fixed income investments. Fluctuations in

actual equity market returns and changes in interest rates may result in changes to pension costs in

future periods.

The Company’s accounting policy is to amortize the net actuarial gain or loss that exceeds 10 per cent of

the greater of the projected benefit obligation / accumulated post-retirement benefit obligation (“PBO”)

and the market-related value of assets, over active plan members’ average remaining service period. For

the largest plans this is currently 8.2 years (8.4 years for 2024 benefit cost) for Canadian plans and a

weighted average of 11.6 years for US plans. The Company’s use of smoothed asset values reduces

volatility related to amortization of actuarial investment experience. As a result, the main cause of volatility

in reported pension cost is the discount rate used to determine the PBO.

The discount rate used to determine benefit costs is based on the yield of high quality long-term corporate

bonds in each operating entity’s country and is determined with reference to bonds which have the same

duration as the PBO as at January 1 of the fiscal year. The following table shows the discount rate for

benefit cost purposes and the expected return on plan assets for each plan:

2024

2023

Discount rate for

benefit cost

purposes

Expected

return on

plan assets

Discount rate for

benefit cost

purposes

Expected

return on

plan assets

TECO Holdings Group Retirement Plan

5.27%

7.05%

5.55%

7.05%

TECO Holdings Group Supplemental

Executive Retirement Plan

(1)

5.15%

N/A

5.45%/5.31%

N/A

TECO Holdings Group Benefit

Restoration Plan (1)

5.18%

N/A

5.48/5.30/5.49%

N/A

TECO Holdings Post-retirement Health

and Welfare Plan

5.28%

N/A

5.53%/6.14%

N/A

NMGC Retiree Medical Plan

5.28%

4.25%

5.55%

2.50%

NSPI

4.63%, 4.62%

6.00%

5.17%, 5.19%

6.25%

GBPC Salaried

5.75%

6.00%

5.75%

6.00%

GBPC Union

5.75%

5.35%

5.75%

5.35%

(1) The discount rate for benefit cost purposes is updated throughout the year as special events occur,

such as settlements and

curtailments

Based on management’s estimate, the reported benefit cost for defined benefit and defined contribution

plans was $56 million in 2024 (2023 – $43 million). The reported benefit cost is impacted by numerous

assumptions, including the discount rate and asset return assumptions. A 0.25 per cent change in the

discount rate and asset return assumptions would have had +/- impact on the 2024 benefit cost of $0.5

million and $3.0 million, respectively (2023 – $0.5 million and $2.5 million).

Unbilled Revenue

Electric and gas revenues are billed on a systematic basis over a one or two-month period for NSPI and a

one-month period for other Emera utilities. At the end of each month, the Company must make an

estimate of energy delivered to customers since the date their meter was last read and determine related

revenues earned but not yet billed. The unbilled revenue is estimated based on several factors, including

current month’s generation, estimated customer usage by class, weather, line losses, inter-period

changes to customer classes and applicable customer rates. Based on the extent of estimates included in

determination of unbilled revenue, actual results may differ from the estimate. At December 31, 2024,

unbilled revenues totalled $342 million (2023 – $363 million) on total regulated operating revenues of

$7,447 million (2023 – $7,235 million).

PP&E

PP&E represents 61 per cent of total assets on the Company’s balance sheet and includes generation,

transmission and distribution, and other assets of the Company.

Depreciation is determined by the straight-line method, based on the estimated remaining service lives of

depreciable assets in each category. The service lives of regulated PP&E are determined based on

depreciation studies and require appropriate regulatory approval. Due to the magnitude of the Company’s

PP&E, changes in estimated depreciation rates can have a material impact on depreciation expense and

accumulated depreciation.

Depreciation expense was $1,135 million for the year ended December 31, 2024 (2023 – $1,019 million).

Goodwill Impairment Assessments

Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated FV of

identifiable assets acquired, and liabilities assumed at the acquisition date.

Goodwill is subject to assessment for impairment at the reporting unit level annually, or if an event or

change in circumstances indicates that the FV of a reporting unit may be below its carrying value.

Application of the goodwill impairment test requires management judgment on significant assumptions

and estimates. When assessing goodwill for impairment, the Company has the option of first performing a

qualitative assessment to determine whether a quantitative assessment is necessary. In performing a

qualitative assessment, management considers, among other factors, macroeconomic conditions,

industry and market considerations and overall financial performance.

If the Company performs a qualitative assessment and determines it is more likely than not that its FV is

less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a

quantitative test is performed. The quantitative test compares the FV of the reporting unit to its carrying

amount, including goodwill. If the carrying amount of the reporting unit exceeds its FV, an impairment loss

is recorded. Significant assumptions used in estimating the FV of a reporting unit include discount and

growth rates, rate case assumptions including future cost of capital, valuation of the reporting units' net

operating loss (“NOL”), and projected operating and capital cash flows. Adverse changes in these

assumptions could result in a future material impairment of the goodwill assigned to Emera’s reporting

units.

As of December 31, 2024, Emera’s goodwill represents the excess of the acquisition purchase price for

TECO Energy, Inc. (TEC, PGS and NMGC reporting units) over the FV assigned to identifiable assets

acquired and liabilities assumed. In Q3 2024, Emera entered into an agreement to sell NMGC. As a

result, a quantitative goodwill impairment assessment was performed on the NMGC reporting unit and the

Company recorded a goodwill impairment charge of $210 million ($198 million, after-tax) or $155 million

USD ($146 million USD, after-tax). The reduced NMGC goodwill balance of $303 million is included in the

NMGC disposal unit classified as held for sale. For further details, refer to note 23 in the consolidated

financial statements.

In Q4 2024, a qualitative assessment was performed for TEC, given the significant excess of FV over

carrying amounts calculated during the last quantitative test in Q4 2023. Management concluded it was

more likely than not that the FV of this reporting unit exceeded its carrying amount, including goodwill. As

such, no quantitative testing was required. Given the length of time passed since the last quantitative

impairment test for the PGS reporting unit, Emera elected to bypass a qualitative assessment and

performed a quantitative impairment assessment in Q4 2024 using a combination of the income and

market approach. This assessment estimated that the FV of the PGS reporting unit exceeded its carrying

amount, including goodwill, and as a result no impairment charges were recognized.

As of December 31, 2024, the Company had goodwill with a total carrying amount of $5,858 million

(December 31, 2023 – $5,871 million). The change in the carrying value of goodwill from 2023 to 2024

was primarily a result of the impairment of the goodwill assigned to the NMGC reporting unit and NMGC

goodwill included in disposal units classified as held for sale, partially offset by the effect of the FX

translation of Emera’s foreign affiliates.

Long-Lived Assets Impairment Assessments

The Company assesses whether there has been an impairment of long-lived assets and intangibles when

a triggering event occurs, such as a significant market disruption or the sale of a business. The

assessment involves comparing undiscounted expected future cash flows, to the carrying value of the

asset. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the

amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-

lived asset over its estimated FV.

The Company believes accounting estimates related to asset impairments are critical estimates, as they

are highly susceptible to change and the impact of an impairment on reported assets and earnings could

be material. Management is required to make assumptions based on expectations regarding results of

operations for significant/indefinite future periods and current and expected market conditions in such

periods. Markets can experience significant uncertainties. Estimates based on the Company’s

assumptions relating to future results of operations or other recoverable amounts are based on a

combination of historical experience, fundamental economic analysis, observable market activity and

independent market studies. The Company’s expectations regarding uses and holding periods of assets

are based on internal long-term budgets and projections, which consider external factors and market

forces, as of the end of each reporting period. Assumptions made by management are consistent with

generally accepted industry approaches and assumptions used for valuation and pricing activities.

In 2024, impairment charges of $19 million ($14 million after-tax) were recognized on certain assets, $8

million of which was included in “Other income, net” with $11 million included in “Impairment Charges” on

the Consolidated Income Statement. No impairment charges related to long-lived assets were recognized

in 2023.

Income Taxes

Income taxes are determined based on expected tax treatment of transactions recorded in the

consolidated financial statements. In determining income taxes, tax legislation is interpreted in a variety of

jurisdictions, the likelihood that deferred income tax assets will be recovered from future taxable income is

assessed, and assumptions are made about expected timing of reversal of deferred income tax assets

and liabilities. Uncertainty associated with application of tax statutes and regulations and outcomes of tax

audits and appeals, requires that judgments and estimates be made in the accrual process and in

calculation of effective tax rates. Only income tax benefits that meet the “more likely than not” threshold

may be recognized or continue to be recognized. Unrecognized tax benefits are evaluated quarterly and

changes are recorded based on new information, including issuance of relevant guidance by the courts or

tax authorities and developments occurring in examinations of the Company’s tax returns.

The Company believes accounting estimates related to income taxes are critical estimates. Realization of

deferred income tax assets depends on the generation of sufficient taxable income, both operating and

capital, in future periods. A change in estimated valuation allowance could have a material impact on

reported assets and results of operations. Administrative actions of tax authorities, changes in tax law or

regulation, and uncertainty associated with the application of tax statutes and regulations, could change

the Company’s estimate of income taxes, including the potential for elimination or reduction of the

Company’s ability to realize tax benefits and to utilize deferred income tax assets.

Asset Retirement Obligations

Measurement of the FV of AROs requires the Company to make reasonable estimates concerning the

method and timing of settlement associated with legally obligated costs. There are uncertainties in

estimating future asset-retirement costs due to potential events, such as changing legislation or

regulations, and advances in remediation technologies. Emera has AROs associated with remediation of

generation, transmission, distribution and pipeline assets.

An ARO represents the FV of estimated cash flows necessary to discharge the future obligation using the

Company’s credit-adjusted risk-free rate. The amounts are reduced by actual expenditures incurred.

Estimated future cash flows are based on completed depreciation studies, remediation reports, prior

experience, estimated useful lives, and governmental regulatory requirements. The present value of the

liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased.

The amount capitalized at inception is depreciated in the same manner as the related long-lived asset.

Over time, the liability is accreted to its estimated future value. Accretion expense is included as part of

“Depreciation and amortization expense”. Any accretion expense not yet approved by the regulator is

recorded in “PP&E” and included in the next depreciation study. Accordingly,

changes to the ARO or cost

recognition attributable to changes in the factors discussed above, should not impact the results of

operations of the Company.

Some of the Company’s transmission and distribution assets may have conditional AROs that are not

recognized in the consolidated financial statements as the FV of these obligations could not be

reasonably estimated given insufficient information to do so. A conditional ARO refers to a legal obligation

to perform an asset retirement activity in which the timing and/or method of settlement are conditional on

a future event that may or may not be within the control of the entity. Management monitors these

obligations and a liability is recognized at FV when an amount can be determined.

As at December 31, 2024, AROs recorded on the balance sheet were $217 million (2023 – $192 million).

The Company estimates the undiscounted amount of cash flow required to settle the obligations is

approximately $453 million (2023 – $426 million), which will be incurred between 2025 and 2061. The

majority of these costs will be incurred between 2028 and 2050.

Financial Instruments

The Company is required to determine the FV of all derivatives except those that qualify for the NPNS

exception. FV is the price that would be received for the sale of an asset or paid to transfer a liability in an

orderly arms-length transaction between market participants at the measurement date. FV measurements

are required to reflect assumptions that market participants would use in pricing an asset or liability based

on the best available information, including the risks inherent in a particular valuation technique, such as

a pricing model, and the risks inherent in the inputs to the model.

Level Determinations and Classifications

The Company uses Level 1, 2, and 3 classifications in the FV hierarchy. The FV measurement of a

financial instrument is included in only one of the three levels and is based on the lowest level input

significant to the derivation of the FV. FV is determined, directly or indirectly,

using inputs that are

observable for the asset or liability. Only in limited circumstances does the Company enter into

commodity transactions involving non-standard features where market observable data is not available or

have contract terms that extend beyond five years.

CHANGES IN ACCOUNTING POLICIES AND PRACTICES

The new USGAAP accounting policy that is applicable to, and adopted by the Company in 2024, is

described as follows:

Improvements to Reportable Segment Disclosures

The Company adopted Accounting Standard Update (“ASU”) 2023-07, Segment Reporting (Topic 280),

Improvements to Reportable Segment Disclosures. The change in the standard improves reportable

segment disclosure requirements, primarily through enhanced disclosures about significant segment

expenses. The changes improve financial reporting by requiring disclosure of incremental segment

information on an annual and interim basis for all public entities to enable investors to develop more

decision-useful financial analyses. The guidance was effective for annual reporting periods beginning

after December 15, 2023, and for interim periods beginning after December 15, 2024. Adoption of the

standard resulted in additional qualitative disclosures provided in note 5.

Future Accounting Pronouncements

The Company considers the applicability and impact of all ASUs issued by the Financial Accounting

Standards Board (“FASB”). The following updates have been issued by the FASB, but as allowed, have

not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be

either not applicable to the Company or to have an insignificant impact on the consolidated financial

statements.

Disaggregation of Income Statement Expenses

In November 2024, the FASB issued ASU 2024-03, Income Statement Reporting–Comprehensive

Income–Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement

Expenses. The standard update improves the disclosures about a public business entity’s expenses by

requiring more detailed information about the types of expenses (including purchases of inventory,

employee compensation, depreciation and amortization) included within income statement expense

captions. The guidance will be effective for annual reporting periods beginning after December 15, 2026,

and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The

standard updates are to be applied prospectively with the option for retrospective application. The

Company is currently evaluating the impact of adoption of the standard update on its consolidated

financial statements disclosures.

Improvements to Income Tax Disclosures

In December 2023, the FASB issued ASU 2023-09, Income Taxes

(Topic

740): Improvements to Income

Tax

Disclosures. The standard enhances the transparency, decision usefulness and effectiveness of

income tax disclosures by requiring consistent categories and greater disaggregation of information in the

reconciliation of income taxes computed using the enacted statutory income tax rate to the actual income

tax provision and effective income tax rate, as well as the disaggregation of income taxes paid (refunded)

by jurisdiction. The standard also requires disclosure of income (loss) before provision for income taxes

and income tax expense (recovery) in accordance with U.S. Securities and Exchange Commission

Regulation S-X 210.4-08(h), Rules of General Application – General Notes to Financial Statements:

Income Tax

Expense, and the removal of disclosures no longer considered cost beneficial or relevant.

The guidance will be effective for annual reporting periods beginning after December 15, 2024. Early

adoption is permitted. The standard will be applied on a prospective basis, with retrospective application

permitted. The Company is currently evaluating the impact of adoption of the standard on its consolidated

financial statements disclosures.

SUMMARY OF QUARTERLY

RESULTS

For the quarter ended

millions of dollars

(except per share amounts)

2024

2023

Operating revenues

1,763

1,802

1,617

2,018

1,972

1,740

1,418

2,433

Net income attributable to common

shareholders

154

129

207

289

101

560

EPS – basic

0.52

0.01

0.45

0.73

1.04

0.37

0.10

2.07

EPS – diluted

0.52

0.01

0.45

0.73

1.04

0.37

0.10

2.07

Quarterly operating revenues and adjusted net income are affected by seasonality. The first quarter

provides strong earnings contributions due to a significant portion of the Company’s operations being in

northeastern North America, where winter is the peak electricity usage season. The third quarter provides

strong earnings contributions due to summer being the heaviest electric consumption season in Florida.

Seasonal and other weather patterns, as well as the number and severity of storms, can affect demand

for energy and the cost of service. Quarterly results could also be affected by items outlined in the

“Significant Items Affecting Earnings” section. Quarter-over-quarter variances are discussed further

below.

Q4 2024 compared to Q4 2023

For explanation of variances, refer to the “Consolidated Income Statement Highlights” section.

Q3 2024 compared to Q3 2023

Q3 2024 net income attributable to common shareholders decreased by $97 million and EPS – basic and

diluted decreased by $0.36 compared to Q3 2023. The decreases were primarily due to charges related

to the pending sale of NMGC; decreased earnings at Emera Energy; lower equity earnings from LIL;

lower Corporate income tax recovery due to decreased losses before provision for income taxes;

increased Corporate interest expense due to increased interest rates and increased total debt; and

increased Corporate preferred share dividends. These changes were partially offset by decreased MTM

losses; increased earnings at TEC, PGS, NSPI and NMGC; and lower Corporate OM&G due to the timing

difference in the valuation of long-term incentive expense and related hedges. The change in EPS was

also impacted by an increase in weighted average shares outstanding.

Q2 2024 compared to Q2 2023

Q2 2024 net income attributable to common shareholders increased by $101 million and EPS – basic and

diluted increased by $0.35 compared to Q2 2023. The increases were primarily due to the gain on sale of

LIL, after transaction costs; increased earnings at PGS and TEC; increased Corporate income tax

recovery due to increased losses before provision for income taxes; and decreased MTM losses. These

changes were partially offset by decreased earnings at NMGC and NSPI; higher Corporate interest

expense due to increased interest rates and increased total average debt; and FX losses on the

translation of USD short-term debt balances in Corporate. The change in EPS was also impacted by an

increase in weighted average shares outstanding.

Q1 2024 compared to Q1 2023

Q1 2024 net income attributable to common shareholders decreased by $353 million and EPS – basic

and diluted decreased by $1.34 compared to Q1 2023. The decreases were primarily due to increased

MTM losses; lower earnings at TEC, NMGC, NSPI and EES; increased Corporate OM&G due to the

timing difference in the valuation of long-term incentive expense and related hedges; and increased

Corporate interest expense due to increased total debt. These changes were partially offset by higher

earnings at PGS and NSPML; and higher income tax recovery at Corporate. The change in EPS was also

impacted by an increase in weighted average shares outstanding.