EX-99.2

Exhibit 99.2

Management’s Discussion & Analysis

As at February 26, 2024

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, 2023 relative to the same periods in 2022

and selected financial information for 2021; and its financial position as at December 31, 2023 relative to

December 31, 2022. 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, 2023.

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, 2023, Emera’s rate-regulated subsidiaries and investments

include:

Emera Rate-Regulated Subsidiary or Equity

Investment

Accounting Policies Approved/Examined By

Subsidiary

Tampa Electric Company (“TEC”)

(1)

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”)

(1)

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

Labrador Island Link Limited Partnership (“LIL”)

Newfoundland and Labrador Board of Commissioners of

Public Utilities

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

(1) Effective January 1, 2023, Peoples Gas System ceased to be a division of TEC and the gas utility was

reorganized, resulting in a

separate legal entity called Peoples Gas System, Inc., a wholly owned direct subsidiary of TECO Gas Operations, Inc.

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.

Exhibit 99.2

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,

carbon dioxide emissions reduction goals, 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.

Exhibit 99.2

The 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; operating and maintenance risks; changes in economic conditions;

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

dividend 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; global climate change; 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

Based in Halifax, Nova Scotia, Emera owns and operates cost-of-service rate-regulated electric and gas

utilities in Canada, the United States (“US”) and the Caribbean. Cost-of-service utilities provide essential

electric and gas services in designated territories under franchises and are overseen by regulatory

authorities. Emera’s strategic focus continues to be safely delivering cleaner, affordable and reliable

energy to its customers.

The majority of Emera’s investments in rate-regulated businesses are located in Florida with other

investments in Nova Scotia, New Mexico and the Caribbean.

Emera’s portfolio of regulated utilities

provides reliable earnings, cash flow and dividends. Earnings opportunities in regulated utilities are

generally driven by the magnitude of net investment in the utility (known as “rate base”), and the amount

of equity in the capital structure and the return on that equity (“ROE”) as approved through regulation.

Earnings are also affected by sales volumes and operating expenses.

Emera’s capital investment plan is approximately $9 billion over the 2024 through 2026 period with

approximately $2 billion of additional potential capital investments over the same period. The capital

investment plan and additional potential capital result in an anticipated compound annual rate base

growth in the range of approximately 7 per cent to 8 per cent through 2026. The capital investment plan

includes significant investments across the portfolio in renewable and cleaner generation, reliability and

system integrity investments, infrastructure modernization,

infrastructure expansion to meet the needs of

new and existing customers, and technologies to better support the business and customer experiences.

It is anticipated that approximately 75 per cent of Emera’s $9 billion capital investment plan over the 2024

through 2026 period will be made in Florida.

Emera’s capital investment plan is being funded primarily through internally generated cash flows, debt

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

sales. Generally, equity requirements in support of the Company’s capital investment plan 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 at-the-market program (“ATM program”). Maintaining

investment-grade credit ratings is a priority of the Company.

Exhibit 99.2

Emera has provided annual dividend growth guidance of four to five per cent through 2026. The

Company targets a long-term dividend payout ratio of adjusted net income of 70 to 75 per cent and, while

the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to

return to that range over time. For further information on the non-GAAP measure “Dividend Payout Ratio

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

section.

Seasonal patterns and other weather events affect demand and operating costs. Similarly, mark-to-

market (“MTM”) adjustments and foreign currency exchange can have a material impact on financial

results for a specific period. Emera’s consolidated net income and cash flows are impacted by

movements in the USD relative to the CAD. Emera may hedge both transactional and translational

exposure. These impacts, as well as the timing of capital investments and other factors, mean results in

any one quarter are not necessarily indicative of results in any other quarter, or for the year as a whole.

Energy markets worldwide are experiencing significant change and Emera is well-positioned to continue

to respond to shifting customer demands and meet the challenges of digitization, decarbonization and

decentralized generation, within complex regulatory environments.

Customers depend on energy and are looking for more choice, better control, and greater reliability. The

costs of decentralized generation and storage have become more competitive and advancing

technologies are transforming how utilities operate and interact with customers. Concurrently, climate

change and the increased frequency of extreme weather events are shaping government energy policy.

This is also creating a need to replace aging infrastructure and make investments to protect and harden

energy systems to deliver energy reliability and system resiliency. These factors combined with inflation,

higher interest rates and higher cost of capital place increased pressure on energy costs, and thus

customer rates, at a time when affordability is a challenge.

Emera’s strategy is centered on delivering value for customers, and in doing so creating value for

shareholders. This includes:

•

investing in cleaner and renewable sources of energy, in the related transmission assets, and in

energy storage needed to support intermittent renewables;

•

supporting increasing demand from customers and the ongoing electrification of other sectors;

•

improving system reliability and resiliency, including replacing aging infrastructure and expanding

systems to service new customers; and

•

investing in new internal and customer-facing technologies for improved cost efficiency and better

customer experiences.

Building on its decarbonization progress, Emera is continuing its efforts by establishing clear carbon

reduction goals and a vision to achieve net-zero carbon dioxide emissions by 2050.

This vision is inspired by Emera’s strong track record, the Company’s experienced team, and a visible

path to Emera’s interim carbon goals. With existing technologies and resources,

and subject to supportive

government and regulatory decisions, Emera is working to achieve the following goals compared to

corresponding 2005 levels:

•

A 55 per cent reduction in carbon dioxide emissions by 2025.

•

The retirement of Emera’s last existing coal unit no later than 2040.

•

An 80 per cent reduction in carbon dioxide emissions by 2040.

Achieving the above climate goals on these timelines is subject to the Company's regulatory obligations

and other external factors beyond Emera's control.

Emera seeks to deliver on its Climate Commitment while maintaining its focus on investing in reliability

and staying focused on the cost impacts for customers. Emera is also committed to identifying emerging

technologies and continuing to work constructively with policymakers, regulators, partners, investors and

customers to achieve these goals and realize its net-zero vision.

Emera is committed to world-class safety, operational excellence, good governance, excellent customer

service, reliability, being an employer of choice, and building constructive relationships.

Exhibit 99.2

NON-GAAP FINANCIAL MEASURES AND RATIOS

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

may not be comparable to similar measures presented by other entities. The non-GAAP measures and

ratios are calculated by adjusting certain GAAP measures for specific items. Management believes

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

better understand and evaluate the business. These measures and ratios are discussed and reconciled

below.

Adjusted Net Income Attributable to Common Shareholders, Adjusted Earnings (Loss) Per

Common Share (“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 the effect of MTM adjustments, the GBPC impairment charge in 2022, and the

impact of the 2022 NSPML unrecoverable costs.

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.

For further detail on these MTM adjustments, refer to the “Consolidated Financial Review”, “Financial

Highlights – Other Electric Utilities”, and “Financial Highlights – Other” sections.

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 driven by the effects of macro-

economic factors on the discount rate calculation. Management believes excluding from net income the

effect of this charge better distinguishes ongoing operations of the business and allows investors to better

understand and evaluate the Company. For further details on the GBPC impairment charge, refer to

“Significant Items Impacting Earnings”, and “Financial Highlights – Other Electric Utilities” sections.

In February 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. The after-tax unrecoverable costs were recognized

in “Income from equity investments” in Emera’s Consolidated Statements of Income. Management

believes excluding these unrecoverable costs from the calculation of adjusted net income better reflects

the underlying operations in the period. For further details on the 2022 NSPML unrecoverable costs, refer

to the “Financial Highlights – Canadian Electric Utilities” section.

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, see the “Dividend Payout Ratio” section.

Emera calculates adjusted net income for the Canadian Electric Utilities, Other Electric Utilities, and Other

segments. Reconciliation to the nearest GAAP measure is included in each segment. Refer to “Financial

Highlights – Canadian Electric Utilities”, “Financial Highlights – Other Electric Utilities” and “Financial

Highlights – Other” sections.

Exhibit 99.2

The following reconciles 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)

2023

2022

2023

2022

2021

Net income attributable to common shareholders

289

483

978

945

510

MTM gain (loss), after-tax

(1)

114

307

169

175

(213)

GBPC impairment charge

(73)

NSPML unrecoverable costs

(2)

(7)

Adjusted net income

175

249

809

850

723

EPS – basic

1.04

1.80

3.57

3.56

1.98

Adjusted EPS – basic

0.63

0.93

2.96

3.20

2.81

(1) Net of income tax expense of $44 million for the three months ended December 31, 2023 (2022 – $124 million expense)

and $68

million expense for the year ended December 31, 2023 (2022 – $73 million expense) (2021 – $86 million recovery).

(2) Emera accounts for NSPML as an equity investment and therefore the after-tax unrecoverable costs were recorded

in “Income

from equity investments” on Emera’s Consolidated Statements of Income.

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.

Similar to adjusted net income calculations described above, adjusted EBITDA represents EBITDA

absent the income effect of MTM adjustments, the 2022 GBPC impairment charge and the 2022 NSPML

unrecoverable costs.

The following is a reconciliation of net income to EBITDA and Adjusted EBITDA:

Three months ended

Year ended

For the

December 31

millions of dollars

2023

2022

2023

2022

2021

Net income

(1)

307

499

1,045

1,009

561

Interest expense, net

241

206

925

709

611

Income tax expense (recovery)

154

128

185

(6)

Depreciation and amortization

264

254

1,049

952

902

EBITDA

863

1,113

3,147

2,855

2,068

MTM gain (loss), before-tax

158

431

237

248

(299)

GBPC impairment charge

(73)

NSPML unrecoverable costs

(2)

(7)

Adjusted EBITDA

705

755

2,910

2,687

2,367

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

(2) Emera accounts for NSPML as an equity investment and therefore the after-tax unrecoverable costs were recorded

in “Income

from equity investments” on Emera’s Consolidated Statements of Income.

Exhibit 99.2

CONSOLIDATED

FINANCIAL REVIEW

Significant Items Affecting Earnings

2023

Earnings Impact of MTM Gain, After-Tax

MTM gain, after-tax decreased $193 million to $114 million in Q4 2023, compared to $307 million in Q4

2022 primarily due to unfavourable changes in existing positions, partially offset by higher amortization of

gas transportation assets in 2022 at Emera Energy Services (“EES”). For the year ended December 31,

2023, MTM gain, after-tax decreased $6 million to $169 million compared to $175 million for the same

period in 2022 primarily due to higher amortization of gas transportation assets at EES, partially offset by

favourable changes in existing positions at EES and gains on Corporate FX hedges.

2022

GBPC Impairment Charge

In Q4 2022, Emera recognized a goodwill impairment charge of $73 million ($0.27 per common share) for

GBPC due to a decline in the FV of the reporting unit driven by the effects of macro-economic factors on

discount rate calculations. This non-cash charge was recorded in “GBPC Impairment charge” on the

Consolidated Statements of Income and reduced the GBPC goodwill balance to nil. For further details,

refer to note 22 in the consolidated financial statements.

TECO Guatemala Holdings (“TGH”) International Arbitration and Award

In Q4 2022, a payment of $63 million ($45 million after tax and legal costs, or $0.17 per common share),

was made by the Republic of Guatemala to TECO Energy in satisfaction of the second and final award

issued by the International Centre of the Settlement of Investment Disputes tribunal regarding a dispute

over an investment of TGH, a wholly owned subsidiary of TECO Energy. The payment was recognized in

‘Other income, net” on the Consolidated Statements of Income. For further details, refer to note 8 in the

consolidated financial statements.

Consolidated Financial Highlights

For the

Three months ended

Year ended

millions of dollars

December 31

Adjusted net income

2023

2022

2023

2022

2021

Florida Electric Utility

115

124

627

596

462

Canadian Electric Utilities

247

222

241

Gas Utilities and Infrastructure

214

221

198

Other Electric Utilities

Other

(71)

(1)

(314)

(218)

(198)

Adjusted net income

175

249

809

850

723

MTM gain (loss), after-tax

114

307

169

175

(213)

GBPC impairment charge

(73)

NSPML unrecoverable costs

(7)

Net income attributable to common shareholders

289

483

978

945

510

Exhibit 99.2

The following table highlights the significant changes in adjusted net income from 2022 to 2023:

For the

Three months ended

Year ended

millions of dollars

December 31

Adjusted net income – 2022

249

850

Operating Unit Performance

Increased earnings at NSPI due to new base rates and increased sales

volumes, partially offset by higher operating, maintenance and general

expenses ("OM&G"), interest expense and depreciation

Increased income from equity investments at NSPML quarter-over-

quarter primarily due to the Maritime Link holdback (the "holdback")

recognized in Q4 2022. Year-over-year also due to the partial reversal in

Q3 2023 of the holdback recognized in 2022

Decreased earnings quarter-over-quarter at TEC due to increased

interest expense, depreciation, state and municipal taxes, unfavourable

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

customer growth driving higher sales volumes. Increased earnings year-

over-year due to new base rates, the impact of a weaker CAD and

customer growth, partially offset by higher interest expense,

depreciation, state and municipal taxes, and OM&G, and unfavourable

weather

(9)

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

lower asset optimization revenues and higher OM&G, partially offset by

new base rates. Increased earnings year-over-year due to new base

rates, partially offset by higher OM&G and interest expense

(11)

Decreased earnings at EES due to more favourable market conditions in

2022

(21)

(22)

Corporate

Decreased OM&G, pre-tax, due to timing of long-term compensation

and related hedges

Increased interest expense, pre-tax, due to higher interest rates and

higher debt levels

(9)

(51)

Decreased income tax recovery quarter-over-quarter primarily due to the

impact of effective state tax rates

(10)

TGH award, after tax and legal costs, in Q4 2022. Refer to the

"Significant Items Affecting Earnings" section

(45)

Other Variances

(3)

Adjusted net income – 2023

175

809

For further details of reportable segments contributions, refer to the "Financial Highlights" section.

For the

Year ended December 31

millions of dollars

2023

2022

2021

Operating cash flow before changes in working capital

2,336

1,147

1,337

Change in working capital

(95)

(234)

(152)

Operating cash flow

2,241

913

1,185

Investing cash flow

(2,917)

(2,569)

(2,332)

Financing cash flow

939

1,555

1,311

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

As at

December 31

millions of dollars

2023

2022

2021

Total assets

39,480

39,742

34,244

Total long-term

debt (including current portion)

18,365

16,318

14,658

Exhibit 99.2

Consolidated Income Statement Highlights

For the

Three months ended

Year ended

millions of dollars

December 31

(except per share amounts)

2023

2022

Variance

2023

2022

Variance

2021

Operating revenues

1,972

2,358

(386)

7,563

7,588

(25)

5,765

Operating expenses

1,467

1,638

171

5,769

5,959

190

4,835

Income from operations

505

720

(215)

1,794

1,629

165

930

Other income, net

102

(51)

158

145

Interest expense, net

241

206

(35)

925

709

(216)

611

Net income attributable to

common shareholders

289

483

(194)

978

945

510

Adjusted net income

175

249

(74)

809

850

(41)

723

Weighted average shares of

common stock outstanding

(in millions)

(1)

277.7

269.0

8.7

273.6

265.5

8.1

257.2

EPS – basic

1.04

1.80

(0.76)

3.57

3.56

0.01

1.98

EPS – diluted

1.04

1.80

(0.76)

3.57

3.55

0.02

1.98

Adjusted EPS – basic

0.63

0.93

(0.30)

2.96

3.20

(0.24)

2.81

Adjusted EBITDA

705

755

(50)

2,910

2,687

223

2,367

Dividends per common share

declared

0.7175

0.6900

0.0275

2.7875

2.6775

0.1100

2.5750

Dividends per first preferred shares declared:

Series A

0.5456

Series B

1.5583

0.6869

0.8714

0.4873

Series C

1.2873

1.1802

0.1071

1.1802

Series E

1.1250

Series F

1.0505

Series H

1.3140

1.2250

0.0890

1.2250

Series J

1.0625

0.6470

Series L

1.1500

0.1638

(1) Effective February 10, 2022, deferred share units are no longer able to be settled in shares and are

therefore excluded from

weighted average shares of common stock outstanding.

Operating Revenues

For Q4 2023, operating revenues decreased $386 million compared to Q4 2022 and, excluding

decreased MTM gains of $286 million, decreased $100 million. The decrease was due to lower fuel

revenues at NMGC, TEC, and NSPI; decreased marketing and trading margin at EES; lower asset

optimization revenue at NMGC; and unfavourable weather at TEC. These decreases were partially offset

by new base rates at TEC, NSPI and NMGC; storm cost recovery surcharge revenue at TEC; customer

growth at TEC and NSPI; and favourable weather at NSPI.

For the year ended December 31, 2023, operating revenues decreased $25 million compared to 2022

and, excluding decreased MTM gains of $62 million, increased $37 million. The increase was due to new

base rates at TEC, NSPI and NMGC; the impact of a weaker CAD; storm cost recovery surcharge

revenue at TEC; and customer growth at TEC and NSPI. These increases were partially offset by lower

fuel revenues at NMGC, TEC, NSPI, PGS and BLPC; lower off-system sales at PGS; a change in fuel

cost recovery methodology for an industrial customer at NSPI; and decreased marketing and trading

margin at EES.

Exhibit 99.2

Operating Expenses

For Q4 2023, operating expenses decreased $171 million compared to Q4 2022 and excluding the 2022

GBPC impairment charge of $73 million, decreased $98 million. For the year ended December 31, 2023,

operating expenses decreased $190 million compared to 2022 and excluding the 2022 GBPC impairment

charge of $73 million, decreased $117 million. The decreases in both periods were due to lower fuel

expenses at TEC, NMGC, and PGS; partially offset by higher OM&G at TEC due to storm restoration

costs recognized related to the storm cost recovery surcharge revenue, and at NSPI due to higher power

generation and transmission and distribution field services cost. Year-over-year the decrease was also

due to a change in fuel cost recovery for an industrial customer at NSPI, partially offset by the impact of a

weaker CAD and the recognition of the Nova Scotia Renewable Electricity Regulations (“RER”) penalty at

NSPI.

Other Income, net

For Q4 2023, other income, net decreased $51 million compared to Q4 2022, primarily due to the TGH

award in Q4 2022. For the year ended December 31, 2023, other income, net increased $13 million

compared to 2022, primarily due to increased FX gains in 2023; higher interest income primarily at TEC;

and higher pension non-current service cost recovery, partially offset by the TGH award in 2022.

Interest Expense, net

Interest expense, net for Q4 2023 increased $35 million, and for the year ended December 31, 2023

increased $216 million compared to the same periods in 2022. The increases in both periods were due to

higher interest rates; higher borrowings to support capital investments and ongoing operations; and the

impact of a weaker CAD.

Net Income and Adjusted Net Income

Net income attributable to common shareholders for Q4 2023, compared to Q4 2022, was unfavourably

impacted by the $193 million decrease in MTM gains, after-tax, and favourably impacted by the $73

million GBPC impairment charge from 2022. Excluding these changes, adjusted net income decreased

$74 million. This was primarily due to the TGH award in Q4 2022; decreased earnings at EES, NMGC

and TEC; lower Corporate income tax recovery; and increased Corporate interest expense. These were

partially offset by increased earnings at NSPI and NSPML; and decreased Corporate OM&G due to the

timing of long-term compensation and related hedges.

Net income attributable to common shareholders for the year ended 2023, as compared to the same

period in 2022, was unfavourably impacted by the $6 million decrease in MTM gains, after-tax, and

favourably impacted by the $73 million GBPC impairment charge and the $7 million in NSPML

unrecoverable costs from 2022. Excluding these changes, adjusted net income decreased $41 million.

The decrease was primarily due to increased Corporate interest expense due to higher interest rates and

increased total debt; the TGH award in Q4 2022; and decreased earnings at EES. These were partially

offset by increased earnings at TEC, NMGC, NSPI and NSPML.

EPS and Adjusted EPS – Basic

EPS and Adjusted EPS – basic were lower for Q4

2023 due to the increase in weighted average shares

of common stock outstanding and decreased earnings as discussed above.

EPS – basic was higher for the year ended December 31, 2023, due to the impact of higher earnings as

discussed above. Adjusted EPS – basic was lower for the year ended December 31, 2023 due to the

increase in weighted average shares of common stock outstanding and decreased adjusted earnings, as

discussed above.

Exhibit 99.2

Effect of Foreign Currency Translation

Emera operates in Canada, the United States 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

for 2023 and 2022 are as follows:

Three months ended

Year ended

December 31

2023

2022

2023

2022

Weighted average CAD/USD

1.36

1.37

1.35

1.34

Period end CAD/USD exchange rate

1.32

1.35

1.32

1.35

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

2023

2022

2023

2022

Florida Electric Utility

466

458

Gas Utilities and Infrastructure

(1)

142

143

Other Electric Utilities

Other segment

(2)

(18)

(95)

(50)

Total

(3)

111

173

539

574

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

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

denominated debt.

(3) Excludes $73 million USD in MTM gain, after-tax, for the three months ended December 31, 2023 (2022 – $222 million USD

MTM gain, after-tax) and MTM gain, after-tax of $116

million USD for the year ended December 31, 2023 (2022 – $130 million USD

MTM gain, after-tax) and the GBPC impairment charge of nil for the three months and year ended December 31, 2023

(2022 – $54

million USD).

The translation impact of the change in FX rates on foreign denominated earnings increased net income

by $13 million in Q4 2023 and $46 million for the year ended December 31, 2023, compared to the same

periods in 2022. The translation impact of the change in FX rates on foreign denominated earnings

decreased adjusted net income by $3 million in Q4 2023 and increased adjusted net income by $20

million for the year ended December 31, 2023 compared to the same periods in 2022. Impacts of the

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

translation risk of USD earnings in the Other segment.

BUSINESS OVERVIEW AND OUTLOOK

Emera’s 2023 results were impacted by macroeconomic conditions, specifically higher interest rates as

well as other impacts of inflation. These macroeconomic conditions are likely to continue for the near

term. For information on general economic risk, including interest rate and inflation risk, refer to the

“Enterprise Risk and Risk Management – General Economic Risk” section.

Exhibit 99.2

Florida Electric Utility

Florida Electric Utility 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 $12 billion USD of assets and approximately 840,000 customers at December 31, 2023. TEC owns

6,433 megawatts (“MW”) of generating capacity, of which 74 per cent is natural gas fired, 19 per cent is

solar and 7 per cent is coal. TEC owns 2,192 kilometres of transmission facilities and 20,299 kilometres of

distribution facilities. TEC meets the planning criteria for reserve capacity established by the FPSC, which

is a 20 per cent reserve margin over firm peak demand.

TEC’s approved regulated ROE range is 9.25 per cent to 11.25 per cent, based on an allowed equity

capital structure of 54 per cent. An ROE of 10.20 per cent is used for the calculation of the return on

investments for clauses.

TEC anticipates earning towards the lower end of the ROE range in 2024 but expects earnings to be

higher than 2023. Normalizing 2023 for weather, TEC sales volumes in 2024 are projected to be higher

than 2023 due to customer growth. TEC expects customer growth rates in 2024 to be comparable to

2023, reflective of the expected economic growth in Florida.

On February 1, 2024, TEC notified the FPSC of its intent to seek a base rate increase effective January

2025, reflecting a revenue requirement increase of approximately $290 to $320 million USD and

additional adjustments of approximately $100 million USD and $70 million USD for 2026 and 2027,

respectively. TEC’s proposed rates include recovery of solar generation projects, energy storage

capacity, a more resilient and modernized energy control center, and numerous other resiliency and

reliability projects. The filing range amounts are estimates until TEC files its detailed case in April 2024.

The FPSC is scheduled to hear the case in Q3 2024 with a decision expected by the end of 2024.

On August 16, 2023, TEC filed a petition to implement the 2024 Generation Base Rate Adjustment

provisions pursuant to the 2021 rate case settlement agreement. Inclusive of TEC’s ROE adjustment, the

increase of $22 million USD was approved by the FPSC on November 17, 2023.

On January 23, 2023, TEC petitioned the FPSC for recovery of the storm reserve regulatory asset and

the replenishment of the balance in the storm reserve to the approved storm reserve level of $56 million

USD, for a total of $131 million USD.

The storm cost recovery surcharge was approved by the FPSC on

March 7, 2023, and TEC began applying the surcharge in April 2023. Subsequently, on November 9,

2023, the FPSC approved TEC’s petition, filed on August 16, 2023, to update the total storm cost

collection to $134 million USD. It also changed the collection of the expected remaining balance of $29

million USD as of December 31, 2023, from over the first three months of 2024 to over the 12 months of

2024. The storm recovery is subject to review of the underlying costs for prudency and accuracy by the

FPSC and issuance of an order by the FPSC is expected by Q3 2024.

In Q3 2023, TEC was impacted by Hurricane Idalia. The related storm restoration costs were

approximately $35 million USD, which were charged to the storm reserve regulatory asset, resulting in

minimal impact to earnings. TEC will determine the timing of the request for recovery of Hurricane Idalia

costs at a future time.

On January 23, 2023, TEC requested an adjustment to its fuel charges to recover the 2022 fuel under-

recovery of $518 million USD over a period of 21 months. The request also included an adjustment to

2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a

projected reduction of $170 million USD for the balance of 2023. The changes were approved by the

FPSC on March 7, 2023, and were effective beginning on April 1, 2023.

In 2024, capital investment in the Florida Electric Utility segment is expected to be $1.3 billion USD (2023

– $1.3 billion USD), including allowance for funds used during construction (“AFUDC”). Capital projects

include solar investments,

grid modernization, storm hardening investments and building resilience.

Exhibit 99.2

Canadian Electric Utilities

Canadian Electric Utilities includes NSPI and ENL. 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. ENL is a holding company with equity investments in NSPML and LIL: two

transmission investments related to the development of an 824 MW hydroelectric generating facility at

Muskrat Falls on the Lower Churchill River in Labrador.

NSPI

With $7.2 billion of assets and approximately 549,000 customers, 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 532 MW of capacity.

NSPI also has rights to 153 MW of Maritime Link capacity, representing Nalcor Energy’s (“Nalcor”) Nova

Scotia Block (“NS Block”) delivery obligations,

as discussed below. NSPI owns approximately 5,000

kilometres of transmission facilities and 28,000 kilometres of distribution facilities.

Nalcor 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, Nalcor 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 Nalcor through

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

bid from Nalcor 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 expects earnings and sales volumes to be higher in 2024 than 2023 but anticipates earning below

its allowed ROE range in 2024.

On January 29, 2024, NSPI applied to the UARB for approval of a structure that would begin to recover

the outstanding Fuel Adjustment Mechanism (“FAM”) balance. As part of the application, NSPI requested

approval for the sale of $117 million of the FAM

regulatory asset to Invest Nova Scotia, a provincial

Crown corporation, with the proceeds paid to NSPI upon approval. NSPI has requested approval to

collect from customers the amortization and financing costs of $117 million on behalf of Invest Nova

Scotia over a 10-year period, and remit those amounts to Invest Nova Scotia as collected, reducing short-

term customer rate increases relative to the currently established FAM process. If approved, this portion

of the FAM regulatory asset would be removed from the Consolidated Balance Sheets and NSPI would

collect the balance on behalf of Invest Nova Scotia in NSPI rates beginning in 2024. A decision is

expected in the first half of 2024. It is anticipated that NSPI will apply to the UARB later in 2024 to collect

additional under-recovered fuel amounts in 2025 or future periods, subject to the approval of the UARB.

On October 31, 2023, NSPI submitted an application to the UARB to defer $24 million in incremental

operating costs incurred during Hurricane Fiona storm restoration efforts in September 2022. NSPI is

seeking amortization of the costs over a period to be approved by the UARB during a future rate setting

process. At December 31, 2023, the $24 million is deferred to “Other long-term assets”, pending UARB

approval. A decision is expected from the UARB in 2024.

Exhibit 99.2

On September 16, 2023, Nova Scotia was struck by post-tropical storm Lee and as a result,

approximately 280,000 customers lost power. The total cost of storm restoration was $19 million, with $9

million charged to “OM&G”, $5 million capitalized to property, plant and equipment (“PP&E) and $5 million

deferred to the UARB approved storm rider. The storm rider, for each of 2023, 2024, and 2025, allows

NSPI to apply to the UARB for deferral and recovery of expenses if major storm restoration expenses

exceed approximately $10 million in any given year. The application for deferral of the storm rider is made

in the year following the year of the incurred costs, with recovery beginning in the year after the

application.

On February 2, 2023, the UARB approved the General Rate Application settlement agreement between

NSPI, key customer representatives and participating interest groups. This resulted in average customer

rate increases of 6.9 per cent effective on February 2, 2023, and a further average increase of 6.5 per

cent on January 1, 2024, with any under or over-recovery of fuel costs addressed through the UARB’s

established FAM process. It also established a storm rider, described above, and a demand-side

management rider. On March 27, 2023, the UARB issued a final order approving the electricity rates

effective on February 2, 2023.

In 2024, capital investment, including AFUDC, is expected to be $435 million (2023 – $451 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 of Nova Scotia (the “Province”). NSPI continues to work with both levels of government to

comply with these laws and regulations to maximize efficiency of emission control measures and

minimize customer cost. NSPI anticipates that costs prudently incurred to achieve legislated compliance

will be recoverable under NSPI’s regulatory framework. NSPI faces risks associated with achieving

climate-related and environmental legislative requirements, including the risk of non-compliance, which

could adversely affect NSPI’s operations and financial performance. For further discussion on these risks

and environmental legislation and regulations, refer to the “Enterprise Risk and Risk Management”

section. Recent developments related to provincial and federal environmental laws and regulations are

outlined below.

Clean Electricity Solutions Task Force:

The Clean Electricity Solutions Task Force (the “Task

Force”) was created by the Province in April 2023

to advise the provincial government on Nova Scotia’s transition away from coal to more renewable

sources of energy. On February 23, 2024, the Task

Force released its report and recommendations,

based on engagement with stakeholders, including NSPI. The Task Force report focuses on findings

related to system operations, regulatory oversight, reliability, transmission and affordability.

The Task

Force announced a number of recommendations, including a strengthening of the authority and

independence of the regulator and the establishment of an independent system operator, in order to

support the continuing transition to clean energy and the achievement of federal and provincial clean

energy goals and legislation. The Province announced they intend to accept these recommendations and

will table enabling legislation in its upcoming session which starts February 27, 2024.

RER:

On April 6, 2023, the Province levied a $10 million penalty on NSPI for non-compliance with the RER

compliance period ending in 2022. The penalty was recorded in “OM&G” on the Consolidated Statements

of Income. On May 26, 2023, NSPI initiated an appeal of the penalty through a proceeding with the

UARB, as permitted under the RER. On October 12, 2023, the UARB decided that it will hear the appeal

by giving due deference to the Province’s decision but permitting the filing of new evidence to support the

parties’ positions. The hearing for the matter is scheduled for June 2024 and a decision is expected

before the end of 2024.

Exhibit 99.2

Carbon Pricing Regulations:

In November 2022, the Province enacted amendments to the Environment Act which provided the

framework for Nova Scotia to implement an output-based pricing system (“OBPS”) to comply with the

Government of Canada’s 2023 through 2030 carbon pollution pricing regulations effective January 1,

2023. The Government of Canada approved the Province’s proposed system, however the OBPS will be

subject to an interim review by the Government of Canada of the standards effective for 2026. The final

Output-Based Pricing System Reporting and Compliance Regulations were prescribed by Order in

Council dated January 30, 2024. The OBPS implements greenhouse gas (“GHG”) emissions

performance standards for large industrial GHG emitters that vary by fuel type. GHG emissions in excess

of the prescribed intensity standards will be subject to a carbon price that starts at $65 per tonne in 2023

and will increase by $15 per tonne annually, reaching $170 per tonne by 2030. NSPI’s regulatory

framework provides for the recovery of costs prudently incurred to comply with carbon pricing programs

pursuant to NSPI’s FAM.

Nova Scotia Cap-and-Trade Program Regulations:

NSPI was a participant in the Nova Scotia Cap-and-Trade Program and was subject to the 2019 through

2022 compliance period. On March 16, 2023, the Province provided NSPI with emissions allowances

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

accrued of $166 million were reversed in Q1 2023. The credits NSPI purchased from provincial auctions

in the amount of $6 million were not refunded and no further costs were incurred to achieve compliance

with the Nova Scotia Cap-and-Trade Program.

Other Legislation

Electricity Act Amendment:

On November 9, 2023, the Province enacted amendments in the Electricity Act which permit the

Governor in Council to approve energy storage projects proposed by a public utility and owned wholly or

in majority by the public utility if the project is in the best interest of ratepayers. Further, the amendments

to the Electricity Act expand the ability of the Province to require NSPI to enter into power purchase

agreements with renewable generation facilities by further empowering the Province to require NSPI to

enter into an agreement for the sale of the electricity to specified customers. This allows specified

customers to buy renewable electricity from specified producers, with NSPI managing the transmission

and sale of the energy. On December 21, 2023, the Governor in Council enacted regulations which

directed NSPI to install three 50 MW four-hour duration grid-scale batteries as part of the regulated

assets of NSPI.

Performance Standards Penalty Amendment:

On April 12, 2023, the Province enacted amendments to the Public Utilities Act which increased the

cumulative total of administrative penalties that could be levied by the UARB against NSPI for non-

compliance with current and future performance standards in a calendar year from $1 million to $25

million. Any administrative penalties levied against NSPI must be credited to customers and NSPI cannot

recover administrative penalties imposed through rates.

Exhibit 99.2

ENL

Total

equity earnings from NSPML and LIL are expected to be higher in 2024, compared to 2023 resulting

from an increased investment in LIL planned for 2024. Both the NSPML and LIL investments are

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

NSPML

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

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

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

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

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

efficiency and reliability of energy in both provinces. Nalcor’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 December 21, 2023, NSPML received approval to collect up to $164 million from NSPI for the

recovery of costs associated with the Maritime Link in 2024; subject to a holdback of $4 million per month,

as discussed below.

On October 4, 2023 and January 31, 2024, the UARB issued decisions providing clarification on

remaining aspects of the Maritime Link holdback mechanism primarily relating to release of past and

future holdback amounts and requirements to end the holdback mechanism. In these decisions, the

UARB agreed with the Company’s submission that $12 million ($8 million related to 2022 and $4 million

relating to 2023) of the previously recorded holdback remain credited to NSPI’s FAM, with the remainder

released to NSPML and recorded in Emera’s “Income from equity investments. NSPML did not record

any additional holdback in Q4 2023. The UARB also confirmed that the holdback mechanism will cease

once 90 per cent of NS Block deliveries are achieved for 12 consecutive months (subject to potential

relief for planned outages or exceptional circumstances) and the net outstanding balance of previously

underdelivered NS Block energy is less than 10 per cent of the contracted annual amount. In addition, the

UARB increased the monthly holdback amount from $2 million to $4 million beginning December 1, 2023.

NSPML expects to file an application to terminate the holdback mechanism in 2024.

NSPML does not anticipate any significant capital investment in 2024.

LIL

ENL is a limited partner with Nalcor in LIL. Construction of the LIL is complete and the Newfoundland

Electrical System Operator confirmed the asset to be operating suitably to support reliable system

operation and full functionality at 700MW, which was validated by the Government of Canada’s

Independent Engineer issuing its Commissioning Certificate on April 13, 2023.

Upon issuance of the Commissioning Certificate, AFUDC equity earnings ceased and cash equity

earnings and return of equity to Emera commenced. The first distribution was received from the LIL

partnership in Q4 2023.

Equity earnings from the LIL investment are based upon the book value of the equity investment and the

approved ROE. Emera’s current equity investment is $747 million, comprised of $410 million in equity

contribution and $337 million of accumulated equity earnings. Emera’s total equity contribution in the LIL,

excluding accumulated equity earnings, is estimated to be approximately $650 million once the final

costing has been confirmed by Nalcor to determine the amount of the remaining investment.

Exhibit 99.2

Gas Utilities and Infrastructure

Gas Utilities and Infrastructure includes PGS, NMGC, SeaCoast, Brunswick Pipeline and Emera’s equity

investment in M&NP.

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

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

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

Mexico. SeaCoast is a regulated intrastate natural gas transmission company offering services in Florida.

Brunswick Pipeline is a regulated 145-kilometre pipeline delivering re-gasified liquefied natural gas from

Saint John, New Brunswick, to markets in the northeastern United States.

Peoples Gas System

With $2.8 billion USD of assets and approximately 490,000 customers, the PGS system includes 24,300

kilometres of natural gas mains and 13,500 kilometres of service lines. Natural gas throughput (the

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

2023.

Beginning in 2024, the approved ROE range for PGS is 9.15 per cent to 11.15 per cent (2023 – 8.9 per

cent to 11.0 per cent), based on an allowed equity capital structure of 54.7 per cent (2023 – 54.7 per

cent). An ROE of 10.15 per cent (2023 – 9.9 per cent) is used for the calculation of return on investments

for clauses.

New Mexico Gas Company, Inc.

With $1.8 billion USD of assets and approximately 540,000 customers, NMGC’s system includes

approximately 2,408 kilometres of transmission pipelines and 17,657 kilometres of distribution pipelines.

Annual natural gas throughput was approximately 1 billion therms in 2023.

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

Gas Utilities and Infrastructure Outlook

Gas Utilities and Infrastructure USD earnings are anticipated to be higher in 2024 than 2023, primarily

due to a base rate increase effective January 2024 at PGS and an expected base rate increase effective

Q4 2024 at NMGC, partially offset by lower asset optimization revenues expected at NMGC.

PGS expects rate base to be higher than in 2023 and anticipates earning within its allowed ROE range in

2024. USD earnings for 2024 are expected to be to be significantly higher than in 2023 primarily due to

higher revenue from new base rates in support of significant ongoing system investment and continued

customer growth in 2024, which is expected to be consistent with Florida’s population growth rates.

On April 4, 2023, PGS filed a rate case with the FPSC and a hearing for the matter was held in

September 2023. On November 9, 2023, the FPSC approved a $118 million USD increase to base

revenues which includes $11 million USD transferred from the cast iron and bare steel replacement rider,

for a net incremental increase to base revenues of $107 million USD. This reflects a 10.15 per cent

midpoint ROE with an allowed equity capital structure of 54.7 per cent. A final order was issued on

December 27, 2023, with the new rates effective January 2024.

The 2020 PGS rate case settlement provided the ability to reverse a total of $34 million USD of

accumulated depreciation through 2023. PGS reversed $20 million USD of accumulated depreciation in

2023 and $14 million USD in 2022.

Exhibit 99.2

NMGC expects 2024 rate base growth to be consistent with 2023, with slightly lower USD earnings as a

result of lower asset optimization revenues, partially offset by higher revenue from expected new base

rates, effective Q4 2024. NMGC anticipates earning near its authorized ROE in 2024. Customer growth

rates are expected to be consistent with historical trends.

On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates to become effective

Q4 2024. NMGC requested a $49 million USD increase in annual base revenues primarily as a result of

increased operating costs and capital investments in pipeline projects and related infrastructure. The rate

case includes a requested ROE of 10.5 per cent.

A final order from the NMPRC is expected in Q3 2024.

In 2024, capital investment in the Gas Utilities and Infrastructure segment is expected to be

approximately $465 million USD (2023 – $495 million USD), including AFUDC. PGS and NMGC will make

investments to maintain the reliability of their systems and support customer growth.

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.

BLPC

With $517 million USD of assets and approximately 134,000 customers, BLPC owns 243 MW of

generating capacity, of which 96 per cent is oil-fired and four per cent is solar.

BLPC owns approximately

188 kilometres of transmission facilities and 3,839 kilometres of distribution facilities. BLPC’s approved

regulated return on rate base for 2023 was 10 per cent.

GBPC

With $334 million USD of assets and approximately 19,000 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 for 2024 is 8.52 per cent (2023 – 8.32 per

cent).

Other Electric Utilities Outlook

Other Electric Utilities’ USD earnings in 2024 are expected to increase over the prior year.

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.

Exhibit 99.2

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 related to the self-insurance fund of $50 million USD, prior year benefits

recognized on remeasurement of deferred income taxes of $5 million USD, and accumulated depreciation

of $16 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. Management does

not expect the final decision and order to have a material impact on adjusted net income.

In 2024, capital investment in the Other Electric Utilities segment is expected to be approximately $80

million USD (2023 – $47 million USD), primarily in more efficient and cleaner sources of generation,

including renewables and battery storage.

Other

The Other segment includes those 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 Emera Energy and Block Energy LLC (“Block Energy”).

Emera Energy consists of EES, a wholly owned physical energy marketing and trading business and an

equity investment in a 50 per cent joint venture ownership of Bear Swamp, a 660 MW pumped storage

hydroelectric facility in northwestern Massachusetts. Block Energy is a wholly owned technology company

focused on finding ways to deliver renewable and resilient energy to customers.

Corporate items included in the Other segment 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 United States. 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 within its guidance range of $15 to $30 million USD.

The adjusted net loss from the Other segment is expected to be higher in 2024 due to increased interest

expense and lower contribution to net income from Emera Energy primarily as a result of one-time

investment tax credits at Bear Swamp in 2023.

The Other segment does not anticipate any significant capital investment in 2024.

Exhibit 99.2

CONSOLIDATED

BALANCE SHEET HIGHLIGHTS

Significant changes in the Consolidated Balance Sheets between December 31, 2022 and December 31,

2023 include:

millions of dollars

Increase

(Decrease)

Explanation

Assets

Cash and cash equivalents

257

Increased due to cash from operations, proceeds from long-term

debt issuances at PGS and NSPI, and issuance of Emera

common stock. These were partially offset by investment in PP&E

at the regulated utilities, net repayments of debt at TEC, and

dividends paid on Emera common stock

Derivative instruments (current and

long-term)

(156)

Decreased due to settlements of derivative instruments and

decreased pricing on power derivative instruments at NSPI,

partially offset by reversal of 2022 contracts at EES

Regulatory assets (current and long-

term)

(515)

Decreased due to higher fuel clause and storm cost recoveries at

TEC, and reversal of accrued Cap-and-Trade emission

compliance charges at NSPI. These were partially offset by

increased FAM deferrals at NSPI due to an under-recovery of fuel

costs and a change in fuel cost recovery methodology for an

industrial customer, and increased deferred income tax regulatory

assets at NSPI

Receivables and other assets

(current and long-term)

(1,079)

Decreased due to lower gas transportation assets, decreased

cash collateral and lower trade receivables as a result of lower

commodity prices at EES, and settlement of the gas hedge

receivable at NMGC

PP&E, net of accumulated

depreciation and amortization

1,380

Increased due to capital additions in excess of depreciation and

amortization, partially offset by the effect of FX translation of

Emera's non-Canadian affiliates

Goodwill

(141)

Decreased due to the effect of the FX translation of non-Canadian

affiliates

Liabilities and Equity

Short-term debt and long-term debt

(including current portion)

754

Issuance of long-term debt at PGS and NSPI and proceeds from

committed credit facilities at Emera, partially offset by net

repayments under committed credit facilities at NSPI and TEC,

repayment of debt at NMGC, and the effect of the FX translation

of non-Canadian affiliates

Accounts payable

(571)

Decreased due to lower commodity prices at EES, NMGC and

TEC, decreased cash collateral position on derivative instruments

and lower fuel related payables at NSPI

Deferred income tax liabilities, net of

deferred income tax assets

185

Increased due to tax deductions in excess of accounting

depreciation related to PP&E, partially offset by changes in

derivative instruments and increased tax credits related to solar

projects at TEC and Bear Swamp facility upgrades

Derivative instruments (current and

long-term)

(574)

Decreased due to changes in existing positions and reversal of

2022 contracts, partially offset by new contracts in 2023 at EES

Regulatory liabilities (current and

long-term)

(501)

Decreased due to lower deferrals related to derivative instruments

at NSPI and settlement of NMGC gas hedges

Other liabilities (current and long-

term)

(157)

Decreased due to reversal of accrued Cap-and-Trade emissions

compliance charges at NSPI

Common stock

700

Increased due to shares issued

Accumulated other comprehensive

income

(273)

Decreased due to the effect of the FX translation of non-Canadian

affiliates

Retained earnings

219

Increased due to net income in excess of dividends paid

Exhibit 99.2

OTHER DEVELOPMENTS

Increase in Common Dividend

On September 20, 2023, the Emera Board of Directors (the “Board”) approved an increase in the annual

common share dividend rate to $2.87 from $2.76 per common share. The first payment was effective

November 15, 2023. Emera also extended its dividend growth rate target of four to five per cent through

2026.

FINANCIAL HIGHLIGHTS

Florida Electric Utility

Three months ended

Year ended

For the

December 31

millions of USD (except as indicated)

2023

2022

2023

2022

Operating revenues – regulated electric

613

597

2,637

2,523

Regulated fuel for generation and purchased power

162

201

682

832

Contribution to consolidated net income

466

458

Contribution to consolidated net income – CAD

115

124

627

596

Average fuel costs in dollars per MWh

The impact of the change in the FX rate increased CAD earnings for the three months and year ended

December 31, 2023, by $1 million and $22 million, respectively.

Net Income

Highlights of the 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 – 2022

458

Increased operating revenues due to storm cost recovery surcharge

revenue (offset in OM&G), new base rates and customer growth driving

higher sales volumes, partially offset by changes in fuel recovery

clause revenue and unfavourable weather

114

Decreased fuel for generation and purchased power due to lower

natural gas prices

150

Increased OM&G primarily due to storm cost recovery recognition

related to the storm surcharge (offset in revenue) and timing of

deferred clause recoveries

(25)

(136)

Increased depreciation and amortization due to additions to facilities

and generation projects placed in service

(8)

(33)

Increased interest expense due to higher interest rates and higher

borrowings to support capital investments and ongoing operations

(7)

(59)

Increased state, and municipal taxes due to higher retail sales and

higher taxable property placed in service

(8)

(33)

(Increased) decreased income tax expense primarily due to production

tax credits related to solar facilities

(6)

Other

(7)

(2)

Contribution to consolidated net income – 2023

466

Exhibit 99.2

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"))

2023

2022

2023

2022

Residential

1,711

1,381

10,307

10,109

Commercial

803

666

6,462

6,300

Industrial

203

176

2,082

2,111

Other

(1)

(80)

300

2,194

2,352

Total

2,637

2,523

21,045

20,872

(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)

2023

2022

Natural gas

17,843

17,083

Solar

1,748

1,492

Purchased power

1,443

1,685

Coal

744

1,325

Total

21,778

21,585

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 6 in

the consolidated financial statements.

Canadian Electric Utilities

Three months ended

Year ended

For the

December 31

millions of dollars (except as indicated)

2023

2022

2023

2022

Operating revenues – regulated electric

439

421

1,671

1,675

Regulated fuel for generation and purchased power

(1)

234

173

777

950

Contribution to consolidated adjusted net income

247

222

NSPML unrecoverable costs

(7)

Contribution to consolidated net income

247

215

Average fuel costs in dollars per MWh

(2)

(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) 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 (2022 – $134 million expense).

Exhibit 99.2

Canadian 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 dollars

2023

2022

2023

2022

NSPI

141

131

Equity investment in LIL

Equity investment in NSPML

(1)

Contribution to consolidated adjusted net income

247

222

(1) Excludes $7 million in NSPML unrecoverable costs, after-tax, for the year ended December 31, 2022.

Net Income

Highlights of the 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 – 2022

215

Increased operating revenues quarter-over-quarter due to new rates,

increased residential, commercial and other class sales volumes, and

favourable weather, partially offset by decreased industrial sales

volume. Year-over-year decrease primarily due to changes in fuel cost

recovery methodology for an industrial customer

(1)

, partially offset by

quarter-over-quarter impacts noted above

(4)

Increased fuel for generation and purchased power quarter-over-quarter

due to increased commodity prices and partial reversal of Nova Scotia

Cap-and-Trade Program costs accrued in 2022, partially offset by a

change in generation mix. Year-over-year decreased due to reversal of

the Nova Scotia Cap-and-Trade Program provision in 2023, compared

to an expense in 2022, partially offset by increased commodity prices

and the Nova Scotia OBPS carbon tax accrual

(61)

173

Increased FAM deferral quarter-over-quarter due to under-recovery of

fuel costs. Year-over-year decreased due to reversal of the Nova Scotia

Cap-and-Trade provision in 2023, partially offset by increased under-

recovery of fuel costs and changes in the fuel recovery methodology for

an industrial customer

(1)

(69)

Increased OM&G due to higher costs for power generation and

transmission and distribution field services. Year-over-year also

increased due to the recognition of the RER penalty and higher

vegetation management costs

(8)

(46)

Increased depreciation and amortization due to increased PP&E in

service

(3)

(17)

Increased interest expense due to increased interest rates and higher

debt levels

(5)

(34)

Increased income from equity investments at NSPML quarter-over-

quarter primarily due to the holdback recognized in Q4 2022. Year-over-

year also increased due to partial reversal in Q3 2023 of the holdback

recognized in 2022, and higher equity earnings from LIL

NSPML unrecoverable costs in 2022

Other

Contribution to consolidated net income – 2023

247

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

refer to note 6 in the 2023

consolidated financial statements

Exhibit 99.2

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)

2023

2022

2023

2022

Residential

910

834

4,986

4,822

Commercial

463

427

3,053

3,006

Industrial

219

353

2,164

2,480

Other

239

148

Total

1,633

1,642

10,442

10,456

Regulated Fuel for Generation and Purchased Power

Annual production volumes are summarized in the following table:

Production Volumes (GWh)

2023

2022

Coal

3,086

3,771

Natural gas

1,946

1,650

Purchased power

881

910

Petcoke

553

897

Oil

145

251

Total non-renewables

6,611

7,479

Purchased power - IPP,

COMFIT and imports

3,251

2,423

Wind, hydro and solar

1,149

1,105

Biomass

128

127

Total renewables

4,528

3,655

Total production volumes

11,139

11,134

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 OBPS, availability of renewable generation, availability of energy from the NS Block, plant

performance, and compliance with environmental regulations.

The Nova Scotia Cap-and-Trade Program provision related to the accrued cost of acquiring emissions

credits for the 2019 through 2022 compliance period. As of December 31, 2022, NSPI had recognized a

cumulative $166 million accrual in fuel costs related to anticipated purchase of emissions credits and $6

million related to credits purchased from provincial auction. Accrued compliance costs of $166 million

were reversed in Q1 2023 and NSPI does not anticipate further costs related to the Nova Scotia Cap-and-

Trade Program. For further information on the reversal of this non-cash accrual and the FAM regulatory

balance, refer to the “Business Overview and Outlook – Canadian Electric Utilities – NSPI” section and

note 6 in the consolidated financial statements.

Exhibit 99.2

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 6 in the consolidated financial statements.

Gas Utilities and Infrastructure

Three months ended

Year ended

For the

December 31

millions of USD (except as indicated)

2023

2022

2023

2022

Operating revenues – regulated gas

(1)

290

372

1,114

1,296

Operating revenues – non-regulated

Total operating revenue

293

374

1,129

1,308

Regulated cost of natural gas

181

391

614

Contribution to consolidated net income

158

170

Contribution to consolidated net income – CAD

214

221

(1) Operating revenues – regulated gas includes $11

million of finance income from Brunswick Pipeline (2022 – $13 million) for the

three months ended December 31, 2023 and $46 million (2022 – $47 million) for the year ended December 31 2023;

however, it is

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

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

table:

Three months ended

Year ended

For the

December 31

millions of USD

2023

2022

2023

2022

PGS

NMGC

Other

Contribution to consolidated net income

158

170

Impact of the change in the FX rate on CAD earnings was minimal for the three months ended and

increased CAD earnings for the year ended December 31, 2023, by $8 million.

Exhibit 99.2

Net Income

Highlights of the 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 – 2022

170

Decreased operating revenues due to lower fuel revenues at PGS and

NMGC, and lower off-system sales at PGS, partially offset by new base

rates at NMGC and customer growth at PGS

(71)

(181)

Decreased asset optimization revenue quarter-over-quarter at NMGC

(10)

Decreased cost of natural gas sold due to lower natural gas prices at

PGS and NMGC

223

Increased OM&G primarily due to higher labour and benefit costs

(10)

(20)

Decreased depreciation and amortization expense quarter-over-quarter

due to a higher reversal of accumulated depreciation in 2023 as a

result of the 2021 rate case settlement at PGS. Year-over-year

increase due to asset growth at PGS and NMGC, partially offset by a

higher reversal of accumulated depreciation in 2023 at PGS

(3)

Increased interest expense due to higher interest rates and increased

borrowings to support ongoing operations and capital investments

(10)

(33)

Other

Contribution to consolidated net income – 2023

158

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)

(Therms)

2023

2022

2023

2022

Residential

537

614

414

421

Commercial

315

354

839

836

Industrial

(1)

1,615

1,429

Other

(2)

147

217

266

227

Total

(3)

1,068

1,249

3,134

2,913

(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 (2022 – $47 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.

Exhibit 99.2

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

Gas Volumes by Type

(millions of Therms)

2023

2022

Transportation

2,461

2,206

System supply

673

707

Total

3,134

2,913

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

note 6 in the consolidated financial statements.

Other Electric Utilities

Three months ended

Year ended

For the

December 31

millions of USD (except as indicated)

2023

2022

2023

2022

Operating revenues – regulated electric

104

390

398

Regulated fuel for generation and purchased power

204

223

Contribution to consolidated adjusted net income

Contribution to consolidated adjusted net income – CAD

GBPC Impairment charge

Equity securities MTM gain (loss)

(4)

Contribution to consolidated net income (loss)

(46)

(35)

Contribution to consolidated net income (loss) – CAD

(62)

(48)

Electric sales volumes (GWh)

323

301

1,260

1,239

Electric production volumes (GWh)

345

325

1,362

1,340

Average fuel cost in dollars per MWh

165

161

150

166

On March 31, 2022, Emera completed the sale of its 51.9 per cent interest in Dominica Electricity

Services Ltd. (“Domlec”) for proceeds which approximated carrying value. The sale did not have a

material impact on earnings.

The impact of the change in the FX rate on CAD earnings for the three months and year ended

December 31, 2023 was minimal.

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

table:

Three months ended

Year ended

For the

December 31

millions of USD

2023

2022

2023

2022

BLPC

GBPC

Other

(1)

(3)

Contribution to consolidated adjusted net income

Exhibit 99.2

Net Income

Highlights of the 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 – 2022

(46)

(35)

Increased operating revenues quarter-over-quarter due to higher fuel

revenue at BLPC and GBPC as a result of higher fuel prices and higher

sales volumes at BLPC. Year-over-year decreased due to lower fuel

revenue at BLPC reflecting lower fuel prices, and the sale of Domlec in

Q1 2022, partially offset by interim rates at BLPC and increased sales

volumes at BLPC and GBPC

(8)

Increased fuel for generation and purchased power quarter-over-

quarter due to higher fuel costs at BLPC and GBPC. Decreased year-

over-year due to lower fuel prices and change in generation mix at

BLPC

(3)

GBPC impairment charge in 2022

Other

(6)

(2)

Contribution to consolidated net income – 2023

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

6 in the consolidated financial statements.

Other

Three months ended

Year ended

For the

December 31

millions of dollars

2023

2022

2023

2022

Marketing and trading margin

(1) (2)

143

Other non-regulated operating revenue

Total operating revenues – non-regulated

123

159

Contribution to consolidated adjusted net income (loss)

(71)

(1)

(314)

(218)

MTM gain, after-tax

(3)

112

304

167

179

Contribution to consolidated net income (loss)

303

(147)

(39)

(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 gain, pre-tax of $131 million in Q4 2023 (2022 – $430 million gain) and a gain

$216 million for the year ended December 31, 2023 (2022 – $281 million gain).

(3) Net of income tax expense of $44 million for the three months ended December 31, 2023 (2022 – $124 million expense)

and $68

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

Exhibit 99.2

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

Three months ended

Year ended

For the

December 31

millions of dollars

2023

2022

2023

2022

Emera Energy:

EES

Other

Corporate – see breakdown of adjusted contribution below

(91)

(37)

(356)

(267)

Block Energy LLC

(1)

(4)

(5)

(18)

Other

(1)

(4)

(3)

Contribution to consolidated adjusted net income (loss)

(71)

(1)

(314)

(218)

(1) Previously Emera Technologies

LLC

Net Income

Highlights of the 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 (loss) – 2022

303

(39)

Decreased marketing and trading margin quarter-over-quarter primarily

due to weather driven market conditions in Q4 2022 that increased

pricing and volatility. Year

-over-year decrease reflects less favourable

market conditions, specifically lower natural gas prices and volatility

and higher cost commitments for gas transportation in 2023 compared

to 2022

(37)

(47)

Decreased OM&G, pre-tax, primarily due to the timing of long-term

compensation and related hedges

Increased interest expense, pre-tax, due to increased interest rates

and increased total debt

(8)

(51)

Increased income tax recovery primarily due to increased losses before

provision for income taxes and the recognition of investment tax credits

related to Bear Swamp facility upgrades, partially offset by the impact

of effective state tax rates

TGH award in 2022, after tax and legal costs

(45)

Decreased MTM gain, after-tax, quarter-over-quarter due to

unfavourable changes in existing positions, partially offset by higher

amortization of gas transportation assets in 2022 at EES. Decreased

MTM gain after-tax, year-over-year primarily due to higher amortization

of gas transportation assets partially offset by favourable changes in

existing positions at EES and gains on Corporate FX hedges

(194)

(12)

Other

Contribution to consolidated net income (loss) – 2023

(147)

Exhibit 99.2

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 Florida, United States Gulf Coast and

Midwest/Central Canadian 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 $19 million in Q4 2023, compared to $40

million in Q4 2022; and $46 million ($33 million USD) for the year ended December 31, 2023, compared

to $68 million ($50 million USD) for the same period in 2022. The 2023 and 2022 EES contribution to

consolidated adjusted net income was above the expected EES annual adjusted net income guidance

range of $15 to $30 million USD. Market conditions in 2022 were very favourable, due to high natural gas

pricing and volatility, which reflected weather patterns and geopolitical conditions.

MTM Adjustments

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

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

adjustments. Management believes excluding the effect of MTM valuations, and changes thereto, from

income until settlement better matches the financial effect of these contracts with the underlying cash

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

table below.

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.

Exhibit 99.2

Corporate

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

Three months ended

Year ended

For the

December 31

millions of dollars

2023

2022

2023

2022

Operating expenses

(1)

Interest expense

329

278

Income tax recovery

(25)

(35)

(111)

(109)

Preferred dividends

TGH award, after tax and legal costs

(45)

Other

(2)(3)

(1)

(3)

Corporate adjusted net loss

(4)

(91)

(37)

(356)

(267)

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

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

exposure.

(3) Includes a realized net loss, pre-tax of $4 million ($3 million after-tax) for the three months ended December 31, 2023

(2022 – $5

million net loss, pre-tax and $4 million loss, after-tax) and a $11

million net loss, pre-tax ($8 million after-tax) for the year ended

December 31, 2023 (2022 – $6 million net loss, pre-tax and $5 million loss after-tax) on FX hedges, as discussed

above.

(4) Excludes a MTM gain, after-tax of $15 million for the three months ended December 31, 2023 (2022 – $9 million gain, after-tax)

and a MTM gain, after-tax of $20 million for the year ended December 31, 2023 (2022 – $12 million loss, after-tax).

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 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 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 $9 billion capital investment plan over the 2024 through 2026 period with

approximately $2 billion of additional potential capital investments over the same period. Capital

investments at Emera’s regulated utilities are subject to regulatory approval.

Emera plans to use cash from operations, debt raised at the utilities, equity, and select asset sales 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, 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 credit facilities with varying maturities that cumulatively provide $5.3 billion of credit, with

approximately $2.3 billion undrawn and available at December 31, 2023. The Company was holding a

cash balance of $588 million at December 31, 2023. For further discussion, refer to the “Debt

Management” section below. For additional information regarding the credit facilities, refer to notes 23

and 25 in the consolidated financial statements.

Exhibit 99.2

Consolidated Cash Flow Highlights

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

31, 2023 and 2022 include:

millions of dollars

2023

2022

$ Change

Cash, cash equivalents and restricted cash, beginning of period

332

417

(85)

Provided by (used in):

Operating cash flow before changes in working capital

2,336

1,147

1,189

Change in working capital

(95)

(234)

139

Operating activities

2,241

913

1,328

Investing activities

(2,917)

(2,569)

(348)

Financing activities

939

1,555

(616)

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

(7)

(23)

Cash, cash equivalents, and restricted cash, end of period

588

332

256

Cash Flow from Operating Activities

Net cash provided by operating activities increased

$1,328 million to $2,241 million for the year ended

December 31, 2023, compared to $913 million in 2022.

Cash from operations before changes in working capital increased

$1,189 million for the year ended

December 31, 2023. This increase was due to higher fuel clause recoveries and favourable changes in

the storm reserve balance at TEC, decreased fuel for generation and purchased power expense at NSPI

driven by the decreased Nova Scotia Cap-and-Trade Program provision and a distribution received from

the LIL partnership. This was partially offset by a decrease in regulatory liabilities due to 2022 gas hedge

settlements at NMGC, and receipt of the TGH award in 2022.

Changes in working capital increased operating cash flows by $139 million for the year ended December

31, 2023. This increase was due to favourable changes in accounts receivable at NMGC due to receipt of

its 2022 gas hedge settlement, favourable changes in cash collateral positions at Emera Energy,

favourable changes in natural gas inventory at EES in 2023, and the required prepayment of income

taxes and related interest in 2022 at NSPI. These increases were offset by the timing of accounts payable

payments at NSPI, TEC and NMGC, unfavourable changes in cash collateral positions at NSPI, and

decreased accrual for the Nova Scotia Cap-and-Trade emissions compliance charges at NSPI.

Cash Flow used in Investing Activities

Net cash used in investing activities increased $348 million to $2,917 million for the year ended

December 31, 2023, compared to $2,569 million in 2022. The increase was due to higher capital

investment in 2023.

Capital expenditures for the year ended December 31, 2023, including AFUDC, were $2,976 million

compared to $2,646 million in 2022. Details of 2023 capital spending by segment are shown below:

●

$1,771 million – Florida Electric Utility (2022 – $1,481 million);

●

$461 million – Canadian Electric Utilities (2022 – $518 million);

●

$673 million – Gas Utilities and Infrastructure (2022 – $578 million);

●

$63 million – Other Electric Utilities (2022 – $63 million); and

●

$8 million – Other (2022 – $6 million).

Exhibit 99.2

Cash Flow from Financing Activities

Net cash provided by financing activities decreased $616 million to $939 million for the year ended

December 31, 2023, compared to $1,555 million in 2022. This decrease was due to lower proceeds from

long-term debt at TEC, higher repayment of short-term debt at TEC, lower proceeds from short-term debt

at TECO Finance and Emera, and higher repayments of committed credit facilities at NSPI. This was

partially offset by proceeds from long-term debt at PGS and NSPI, retirement of long-term debt at TEC in

2022, and higher issuance of common stock.

Working Capital

As at December 31, 2023, Emera’s cash and cash equivalents were $567 million (2022 – $310 million)

and Emera’s investment in non-cash working capital was $831 million (2022 – $1,173 million). Of the

cash and cash equivalents held at December 31, 2023, $482 million was held by Emera’s foreign

subsidiaries (2022 – $250 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, 2023, contractual commitments for each of the next five years and in aggregate

thereafter consisted of the following:

millions of dollars

2024

2025

2026

2027

2028

Thereafter

Total

Long-term debt principal

1,670

264

3,047

666

525

12,318

18,490

Interest payment obligations

(1)

836

807

719

626

587

7,438

11,013

Transportation

(2)

696

495

405

388

338

2,597

4,919

Purchased power

(3)

274

249

263

312

3,435

4,845

Fuel, gas supply and storage

556

215

838

Capital projects

778

111

960

Asset retirement obligations

407

423

Pension and post-retirement

obligations

(4)

155

329

Equity investment commitments

(5)

240

Other

154

147

221

659

5,242

2,319

4,661

2,087

1,836

26,571

42,716

(1) 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,

2023, including any expected

required payment under associated swap agreements.

(2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines.

Includes a commitment of

$134 million related to a gas transportation contract between PGS and SeaCoast through 2040.

(3) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths.

(4) The estimated contractual obligation is calculated as the current legislatively required contributions to the registered

funded

pension plans (excluding the possibility of wind-up), 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.

(5) Emera has a commitment to make equity contributions to the LIL related to an investment true up in 2024 and sustaining

capital

contributions over the life of the partnership.

The commercial agreements between Emera and Nalcor require true ups to finalize the

respective investment obligations of the parties in relation the Maritime Link and LIL which is expected to be approximately

$240

million in 2024. In addition, Emera has future commitments to provide sustaining capital to the LIL for routine capital and major

maintenance.

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 February 2022, the UARB issued its decision and Board

Order approving NSPML’s requested rate base of approximately $1.8 billion. In December 2023, the

UARB approved collection of up to $164 million from NSPI for recovery of Maritime Link costs in 2024.

The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are

subject to UARB approval.

Exhibit 99.2

Construction of the LIL is complete and the Newfoundland Electrical System Operator confirmed the

asset to be operating suitably to support reliable system operation and full functionality at 700MW, which

was validated by the Government of Canada’s Independent Engineer issuing its Commissioning

Certificate on April 13, 2023.

Emera has committed to obtain certain transmission rights for Nalcor, if requested, to enable it to transmit

energy which is not otherwise used in Newfoundland and Labrador or Nova Scotia. Nalcor has the right to

transmit this energy from Nova Scotia to New England energy markets 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 2024 forecasted consolidated capital investments are as follows:

millions of dollars

Florida

Electric

Utility

Canadian

Electric

Utilities

Gas Utilities

and

Infrastructure

Other

Electric

Utilities

Other

Total

Generation

266

143

439

New renewable generation

280

Electric transmission

119

207

Electric distribution

496

142

696

Gas transmission and distribution

566

Facilities, equipment, vehicles, and other

567

702

1,728

436

617

105

2,890

Debt Management

In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to

committed syndicated revolving and non-revolving bank lines of credit in either CAD or USD per the table

below.

Undrawn

Credit

and

millions of Canadian dollars (unless otherwise indicated)

Maturity

Facilities

Utilized

Available

Emera – Unsecured committed revolving credit facility

June 2027

900

265

635

TEC (in USD) – Unsecured committed revolving credit facility

December 2026

800

707

NSPI – Unsecured committed revolving credit facility

December 2027

800

332

468

Emera – Unsecured non-revolving facility

December 2024

400

Emera – Unsecured non-revolving facility

February 2024

400

200

Emera – Unsecured non-revolving facility

August 2024

400

TECO Finance (in USD) – Unsecured committed revolving credit

facility

December 2026

400

185

215

NSPI – Unsecured non-revolving facility

July 2024

400

PGS (in USD) – Unsecured revolving facility

December 2028

250

195

TEC (in USD) - Unsecured revolving facility

February 2024

200

TEC (in USD) - Unsecured revolving facility

April 2024

200

NMGC (in USD) – Unsecured revolving credit facility

December 2026

125

104

NMGC (in USD) – Unsecured non-revolving facility

March 2024

Other (in USD) – Unsecured committed revolving credit facilities

Various

Exhibit 99.2

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, 2023.

Emera’s significant covenant is listed below:

As at

Financial Covenant

Requirement

December 31, 2023

Emera

Syndicated credit facilities

Debt to capital ratio

Less than or equal to 0.70 to 1

0.57 : 1

Recent significant financing activity for Emera and its subsidiaries are discussed below by segment:

Florida Electric Utilities

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. Therefore, $497 million

USD of short-term borrowings that was repaid was classified as long-term debt at December 31, 2023.

On November 24, 2023, TEC repaid its $400 million USD unsecured non-revolving facility, which expired

on December 13, 2023.

On April 3, 2023, TEC entered into a 364-day, $200 million USD senior unsecured revolving credit facility

which matures on April 1, 2024. The credit agreement contains customary representations and

warranties, events of default and financial and other covenants, and bears interest at a variable interest

rate, based on either the term secured overnight financing rate (“SOFR”), Wells Fargo’s prime rate, the

federal funds rate or the one-month SOFR, plus a margin. Proceeds from this facility will be used for

general corporate purposes.

On March 1, 2023, TEC entered into a 364-day, $200 million USD senior unsecured revolving credit

facility which matures on February 28, 2024. The credit facility contains customary representations and

warranties, events of default and financial and other covenants, and bears interest at a variable interest

rate, based on either the term SOFR, the Bank of Nova Scotia’s prime rate, the federal funds rate or the

one-month SOFR, plus a margin. Proceeds from this facility will be used for general corporate purposes.

Canadian Electric Utilities

On March 24, 2023, NSPI issued $500 million in unsecured notes. The issuance included $300 million

unsecured notes that bear interest at 4.95 per cent with a maturity date of November 15, 2032, and $200

million unsecured notes that bear interest at 5.36 per cent with a maturity date of March 24, 2053.

Proceeds from these issuances were added to the general funds of the Company and applied primarily to

refinance existing indebtedness, to finance capital investment and for general corporate purposes.

Gas Utilities and Infrastructure

On December 19, 2023, PGS completed an issuance of $925 million USD in senior notes. The issuance

included $350 million USD senior notes that bear interest at 5.42 per cent with a maturity date of

December 19, 2028, $350 million USD senior notes that bear interest at 5.63 per cent with a maturity date

of December 19, 2033 and $225 million USD senior notes that bear interest at 5.94 per cent with a

maturity date of December 19, 2053. Proceeds from these issuances were used to settle intercompany

loan agreements with TEC for the assets and liabilities transferred to PGS as part of the reorganization of

the gas division of Tampa Electric, effective

on January 1, 2023.

Exhibit 99.2

On December 1, 2023, PGS entered into a $250 million USD senior unsecured revolving credit facility

with a group of banks, maturing on December 1, 2028. PGS has the ability to request the lenders to

increase their commitments under the credit facility by up to $100 million USD in the aggregate subject to

agreement from participating lenders. The credit agreement contains customary representations and

warranties, events of default and financial and other covenants, and bears interest at Bankers’

Acceptances or prime rate advances, plus a margin. Proceeds from these facilities will be used for

general corporate purposes.

On October 19, 2023, NMGC issued $100 million USD in senior unsecured notes that bear interest at

6.36 per cent with a maturity date of October 19, 2033. Proceeds from the issuance were used to repay

short-term borrowings.

Other Electric Utilities

On May 24, 2023, GBPC issued a $28 million USD non-revolving term loan that bears interest at 4.00 per

cent with a maturity date of May 24, 2028. Proceeds from this issuance were used to repay GBPC’s $28

million USD bond, which matured in May 2023.

Other

On December 16, 2023, Emera amended its $400 million unsecured non-revolving facility to extend the

maturity date from December 16, 2023 to December 16, 2024. There were no other changes in

commercial terms from the prior agreement.

On August 18, 2023, Emera entered into a $400 million non-revolving term facility which matures on

February 19, 2024. The credit agreement contains customary representations and warranties, events of

default and financial and other covenants, and bears interest at Bankers’ Acceptances or prime rate

advances, plus a margin. Proceeds from this facility will be used for general corporate purposes. On

February 16, 2024, Emera extended the term of this agreement to a maturity date of February 19, 2025.

On June 30, 2023, Emera amended its $400 million unsecured non-revolving facility to extend the

maturity date from August 2, 2023 to August 2, 2024. There were no other changes in commercial terms

from the prior agreement.

On May 2, 2023, Emera issued $500 million in senior unsecured notes that bear interest at 4.84 per cent

with a maturity date of May 2, 2030. The proceeds were used to repay Emera’s $500 million unsecured

fixed rate notes, which matured in June 2023.

Credit Ratings

Emera and its subsidiaries have been assigned the following senior unsecured debt ratings:

Fitch

S&P

Moody's

DBRS

Emera Inc.

BBB (Negative)

BBB- (Negative)

Baa3 (Negative)

N/A

TEC

A (Negative)

BBB+ (Negative)

A3 (Negative)

N/A

PGS (1)

A (Negative)

N/A

NMGC

BBB+ (Negative)

N/A

NSPI

N/A

BBB- (Negative)

N/A

BBB (high)(stable)

(1) On November 10, 2023 Fitch Ratings ("Fitch") assigned first-time long-term issuer default rating of 'A-' to

PGS and an instrument

rating of 'A' for its private placements of senior unsecured bonds.

Exhibit 99.2

Guaranteed Debt

As of December 31, 2023, the Company had $2.75 billion USD (2022 – $2.75 billion USD) senior

unsecured notes ("US Notes”) outstanding.

The US Notes are fully and unconditionally guaranteed, on a joint and several basis, by Emera and

Emera US Holdings Inc. (in such capacity, the “Guarantor Subsidiaries”). Emera owns, directly or

indirectly, all of the limited and general partnership interests in Emera US Finance LP.

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, Emera US Holdings Inc., and Emera US Finance LP (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

2023

2022

Loss from operations

(62)

(73)

Net gains (losses)

(1)

349

(131)

(1) Includes $750 million (2022 – $262 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

2023

2022

Current assets

(1)

223

172

Goodwill

5,871

6,012

Other assets

(2)

6,243

6,402

Total assets

(3)

12,337

12,586

Current liabilities

(4)

1,451

1,903

Long-term liabilities

(5)

6,815

6,431

Total liabilities

8,266

8,334

(1) Includes $179 million (2022 – $144 million) in amounts due from non-guarantor subsidiaries.

(2) Includes $5,941 million (2022 – $6,058 million) in amounts due from non-guarantor subsidiaries.

(3) Excludes investments in non-guarantor subsidiaries. Consolidated Emera total assets are $39,480 million

(2022 – $39,742 million).

(4) Includes $411 million (2022 – $392 million) due to non-guarantor

subsidiaries.

(5) Includes $619 million (2022 – $769 million) due to non-guarantor subsidiaries.

Exhibit 99.2

Outstanding Stock Data

Common Stock

millions of

Issued and outstanding:

dollars

Balance, December 31, 2022

269.95

7,762

Issuance of common stock under ATM program

(1)

8.29

397

Issued under the DRIP,

net of discounts

5.26

272

Senior management stock options exercised and Employee Share Purchase Plan

0.62

Balance, December 31, 2023

284.12

8,462

(1) For the year ended December 31,2023, 8,287,037 common shares were issued under Emera's ATM

program at an average

price of $48.27 per share for gross proceeds of $400 million ($397 million net of after-tax issuance costs). As at December

31,2023, an aggregate gross sales limit of $200 million remained available for issuance under the ATM

program.

As at February 20, 2024, the amount of issued and outstanding common shares was 285.8 million.

If all outstanding stock options were converted as at February 20, 2024, an additional 3.1 million common

shares would be issued and outstanding.

ATM Equity Program

On October 3, 2023, Emera filed a short form base shelf prospectus, primarily in support of the renewal of

its ATM Program in Q4 2023 that will allow the Company to issue up to $600 million of common shares

from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price.

This ATM Program is expected to remain in effect until November 4, 2025.

Preferred Stock

As at February 20, 2024, 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 July 6, 2023, Emera announced it would not redeem the 10 million outstanding Cumulative Rate

Reset Preferred Shares, Series C (“Series C Shares”) or the 12 million outstanding Cumulative Minimum

Rate Reset First Preferred Shares, Series H (“Series H Shares”) on August 15, 2023.

On August 4, 2023, Emera announced after having taken into account all conversion notices received

from holders, no Series C Shares were converted into Cumulative Floating Rate First Preferred Shares,

Series D Shares and no Series H shares were converted into Cumulative Floating Rate First Preferred

Shares, Series I shares. The holders of the Series C Shares are entitled to receive a dividend of 6.434

per cent per annum on the Series C Shares during the five-year period commencing on August 15, 2023,

and ending on (and inclusive of) August 14, 2028 ($0.40213 per Series C Share per quarter). The holders

of the Series H Shares are entitled to receive a dividend of 6.324 per cent per annum on the Series H

Shares during the five-year period commencing on August 15, 2023, and ending on (and inclusive of)

August 14, 2028 ($0.39525 per Series H Share per quarter).

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 three-year period. Expected cash

flow for DB pension plans is $34 million in 2024 (2023 – $42 million). All pension plan contributions are

tax deductible and will be funded with cash from operations.

Exhibit 99.2

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 $46 million for 2024 (2023 –

$45 million).

Defined Benefit Pension Plan Summary

in millions of dollars

Plans by region

TECO Energy

NSPI

Caribbean

Total

Assets as at December 31, 2023

907

1,381

2,298

Accounting obligation at December 31, 2023

896

1,361

2,273

Accounting expense (income) during fiscal 2023

(16)

(11)

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,

2023 totalled $200 million (2022 – $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 are not included within the Consolidated Balance Sheets as at December

31, 2023:

TECO Energy has issued a guarantee in connection with SeaCoast’s performance of obligations under a

gas transportation precedent agreement. The guarantee is for a maximum potential amount of $45 million

USD if SeaCoast fails to pay or perform under the contract. The guarantee expires five years after the

gas transportation precedent agreement termination date, which was terminated on January 1, 2022. In

the event TECO Energy’s and Emera’s long-term senior unsecured credit ratings are downgraded below

investment grade by Moody’s or S&P,

TECO Energy would be required to provide its counterparty a letter

of credit or cash deposit of $27 million USD.

TECO Energy issued a guarantee in connection with SeaCoast’s performance obligations under a firm

service agreement, which expires December 31, 2055, subject to two extension terms at the option of the

counterparty with a final expiration date of December 31, 2071. The guarantee is for a maximum potential

amount of $13 million USD if SeaCoast fails to pay or perform under the firm service agreement. In the

event that TECO Energy’s long-term senior unsecured credit ratings are downgraded below investment

grade by Moody’s or S&P,

TECO Energy would need to provide 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 Inc. has issued 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.

Exhibit 99.2

NSPI has issued guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated, in the

amount of $104 million USD (2022 – $119 million USD) with terms of varying lengths.

The Company has standby letters of credit and surety bonds in the amount of $103 million USD

(December 31, 2022 – $145 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 Inc., 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 2024. The amount committed

as at December 31, 2023 was $56 million (December 31, 2022 – $63 million).

DIVIDEND PAYOUT

RATIO

Emera has provided annual dividend growth guidance of four to five per cent through 2026. The

Company targets a long-term dividend payout ratio of adjusted net income of 70 to 75 per cent and, while

the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to

return to that range over time. Emera’s common share dividends paid in 2023 were $2.7875 ($0.6900 in

Q1, Q2, and Q3 and $0.7175 in Q4) per common share and $2.6775 ($0.6625 in Q1, Q2, and Q3 and

$0.6900 in Q4) per common share for 2022, representing a dividend payout ratio of 78 per cent in 2023

(2022 – 75 per cent) and a dividend payout ratio of adjusted net income of 94 per cent in 2023 (2022 – 83

per cent).

On September 20, 2023, the Board approved an increase in the annual common share dividend rate to

$2.87 from $2.76 per common share. The first quarterly dividend payment at the increased rate was paid

on November 15, 2023.

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 $163 million for the year ended December 31, 2023 (2022 – $157 million).

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 – ENL” 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 $14 million for the year ended December 31, 2023 (2022

– $9 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, 2023 and at December 31, 2022.

Exhibit 99.2

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 an effective, consistent and coherent

approach to risk management. Certain risk management activities for Emera are overseen by the ERMC

to ensure such risks are appropriately identified, assessed, monitored and subject to appropriate controls.

The Board has a Risk and Sustainability Committee (“RSC”) with a mandate 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. It also includes oversight of the Company’s approach to

sustainability and its performance relative to its sustainability objectives.

The Company’s financial risk management activities are focused on those areas that most significantly

impact profitability, quality and consistency of income, and cash flow. Emera’s

risk management focus

extends to key operational risks including safety and environment, which represent core values of Emera.

In this section, Emera describes the principal risks that management believes could materially affect its

business, revenues, operating income, net income, net assets, liquidity or capital resources. The nature

of risk is such that no list is comprehensive, and other risks may arise or risks not currently considered

material may become material in the future.

Regulatory and Political Risk

The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are

subject to risk of the recovery of costs and investments. Regulatory and political risk can include changes

in regulatory frameworks, shifts in government policy, legislative changes, and regulatory decisions.

As cost-of-service utilities with an obligation to serve customers, Emera’s utilities operate under formal

regulatory frameworks, and must obtain regulatory approval to change or add rates and/or riders. Emera

also holds investments in entities in which it has significant influence, and which are subject to regulatory

and political risk including NSPML, LIL, and M&NP.

As a regulated Group II pipeline, the tolls of

Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to the regulatory approval

process described above. In the absence of a complaint, the CER does not normally undertake a detailed

examination of Brunswick Pipeline’s tolls, which are subject to a firm service agreement, expiring in 2034,

with Repsol Energy North America Canada Partnership.

Regulators administer the regulatory frameworks covering material aspects of the utilities’ businesses,

including applying market-based tests to determine the appropriate customer rates and/or riders, the

underlying allowed ROEs, deemed capital structures, capital investment, the terms and conditions for the

provision of service, performance standards, and affiliate transactions. Regulators also review the

prudency of costs and other decisions that impact customer rates and reliability of service and work to

ensure the financial health of the utility for the benefit of customers. Costs and investments can be

recovered upon approval by the respective regulator as an adjustment to rates and/or riders, which

normally require a public hearing process or may be mandated by other governmental bodies.

During

public hearing processes, consultants and customer representatives scrutinize the costs, actions and

plans of these rate-regulated companies, and their respective regulators determine whether to allow

recovery and to adjust rates based upon the evidence and any contrary evidence from other parties. In

some circumstances, other government bodies may influence the setting of rates. Regulatory decisions,

legislative changes, and prolonged delays in the recovery of costs or regulatory assets could result in

decreased rate affordability for customers and could materially affect Emera and its utilities.

Exhibit 99.2

Emera’s utilities generally manage this risk through transparent regulatory disclosure, ongoing

stakeholder and government consultation, and multi-party engagement on aspects such as utility

operations, regulatory audits, rate filings and capital plans. The subsidiaries work to establish

collaborative relationships with regulatory stakeholders, including customer representatives, both through

its approach to filings and additional efforts with technical conferences and, where appropriate, negotiated

settlements.

Changes in government and shifts in government policy and legislation can impact the commercial and

regulatory frameworks under which Emera and its subsidiaries operate. This includes initiatives regarding

deregulation or restructuring of the energy industry. Deregulation or restructuring of the energy industry

may result in increased competition and unrecovered costs that could adversely affect the Company’s

operations, net income and cash flows. State and local policies in some United States 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. Changes in

applicable state or local laws and regulations, including electrification legislation, could adversely impact

PGS and NMGC.

Emera cannot predict future legislative, policy, or regulatory changes, whether caused by economic,

political or other factors, or its ability to respond in an effective and timely manner or the resulting

compliance costs. Government interference in the regulatory process can undermine regulatory stability,

predictability, and independence, and could have a material adverse effect on the Company.

Global Climate Change Risk

The Company is subject to risks that may arise from the impacts of climate change. There is increasing

public concern about climate change and growing support for reducing carbon dioxide emissions.

Municipal, state, provincial and federal governments have been setting policies and enacting laws and

regulations to deal with climate change impacts in a variety of ways, including decarbonization initiatives

and promotion of cleaner energy and renewable energy generation of electricity. Refer to “Changes in

Environmental Legislation” risk below. 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 fewer insurers, more restrictive coverage and increased premiums. Refer to the “Insurance”

section below and “Uninsured Risk”.

Climate change may lead to increased frequency and intensity of events and related impacts such as

hurricanes, ice and other storms, heavy rainfall, cyclones, extreme winds, wildfires, flooding and

droughts. The potential impacts of climate change, such as rising sea levels and larger storm surges from

more intense hurricanes, can combine to produce even greater damage to coastal generation and other

facilities. Climate change is also characterized by rising global temperatures. Increased air temperatures

may bring increased frequency and severity of wildfires within the Company’s service territories. Refer to

“Weather Risk” and “System Operating and Maintenance Risks”.

The Company’s long-term capital investment plan includes significant investment across the portfolio in

renewable and cleaner generation, infrastructure modernization, storm hardening, energy storage and

customer-focused technologies. All these initiatives contribute toward mitigating the potential impacts of

climate change. The Company continues to engage with government, regulators, industry partners and

stakeholders to share information and participate in the development of climate change related policies

and initiatives.

Exhibit 99.2

Physical Impacts:

The Company is subject to physical risks that arise, or may arise, from global climate change, including

damage to operating assets from more frequent and intense weather events and from wildfires due to

warming air temperatures and increasing drought conditions. 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. Refer to “Weather Risk” for further information.

These risks are mitigated to an extent through features such as flood walls at certain plants and through

the location of plants on higher ground. Planned investments in under-grounding parts of the electricity

infrastructure contribute to risk mitigation, as does insurance coverage (for assets other than electricity

transmission and distribution assets). In addition, implementation of regulatory mechanisms for recovery

of costs, such as storm reserves and regulatory deferral accounts, help smooth out the recovery of storm

restoration costs over time.

Reputation:

Failure to address issues related to climate change could affect Emera’s reputation with stakeholders, its

ability to operate and grow, and the Company’s access to, and cost of, capital. Refer to “Liquidity and

Capital Market Risk”. The Company seeks to mitigate this in part by moving away from higher-carbon

generation in favour of lower-carbon generation and non-emitting renewable generation.

Supply Chain:

Changing carbon-related costs, policy and regulatory changes and shifts in supply and demand factors

could lead to more expensive or more scarce products and services that are required by the Company in

its operations. This could lead to supply shortages, delivery delays and the need to source alternate

products and services. The Company seeks to mitigate these risks through close monitoring of such

developments and adaptive changes to supply chain procurement strategies. Refer to “Supply Chain

Risk” and “Uninsured Risk”.

Insurance:

Given concerns regarding carbon-emitting generation, assets and businesses may, over time, become

difficult (or uneconomic) to insure in commercial insurance markets. In the short term, this may be

mitigated through increased investment in engineered protection or alternative risk financing (such as

funded self-insurance or regulatory structures, including storm reserves). Longer-term mitigation may be

achieved through infrastructure siting decisions and further engineered protections. This risk may also be

mitigated through the continued transition away from high-carbon generation sources to sources with low

or zero carbon dioxide emissions.

Policy:

Government and regulatory initiatives, including greenhouse gas emissions standards, air emissions

standards and generation mix standards, are being proposed and adopted in many jurisdictions in

response to concerns regarding the effects of climate change. In some jurisdictions, government policy

has included timelines for mandated shutdowns of coal generating facilities, percentage of electricity

generation from renewables, carbon pricing, emissions limits and cap and trade mechanisms. Over the

medium and longer terms, this 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.

The Company is subject to climate-related and environmental legislative and regulatory requirements.

Such legislative and regulatory initiatives could adversely affect Emera’s operations and financial

performance. Refer to “Regulatory and Political Risk” and “Changes in Environmental Legislation” risk.

The Company seeks to mitigate these risks through active engagement with governments and regulators

to pursue transition strategies that meet the needs of customers, stakeholders and the Company. This

has included NSPI’s participation in negotiated equivalency agreements in Nova Scotia to provide for an

affordable transition to lower-carbon generation. Equivalency agreements allow NSPI to achieve

compliance with federal GHG emissions regulations by meeting provincial legislative and regulatory

requirements as they are deemed to be equivalent. There is no guarantee that such equivalency

agreements will be renewed or remain in force in the future.

Exhibit 99.2

Regulatory:

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. Valuation

impairments could result from such regulatory outcomes. Mitigation efforts in respect of these risks

include active engagement with policy makers and regulators to find mechanisms to avoid such impacts

while being responsive to customers’ and stakeholders’ objectives.

Legal:

The Company could face litigation or regulatory action related to environmental harms from carbon

dioxide emissions or climate change public disclosure issues. The Company addresses these risks

through compliance with all relevant laws, emissions reduction strategies, and public disclosure of climate

change risks.

Water Resources:

For thermal plants requiring cooling water, reduced availability of water resulting from climate change

could adversely impact operations or the costs of operations. The Company seeks ways to reduce and

recycle water as it does in its Polk power plant in Florida, where recovered and treated wastewater is

used in operations to reduce reliance on fresh water supplies in an area where water is not as abundant

as in other markets.

The Company 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. The Company is reinvesting in the

efficiency of certain hydroelectric generation facilities to increase generation capacity and continues to

monitor changing hydrology patterns. Such issues may also affect the availability of purchased power

from third-party owned hydroelectricity sources.

Weather Risk

The Company is subject to risks that arise or may arise from weather including seasonal variations

impacting energy sales, more frequent and intense weather events, changing air temperatures, wildfires

and extreme weather conditions associated with climate change. Refer to “Global Climate Change Risk”.

Fluctuations in the amount of electricity or natural gas used by customers can vary significantly in

response to seasonal changes in weather and could impact the operations, results of operations, financial

condition, and cash flows of the Company’s utilities. For example, TEC could see lower demand in

summer months if temperatures are cooler than expected. Further, extreme weather conditions such as

hurricanes and other severe weather conditions which may be associated with climate change could

cause these seasonal fluctuations to be more pronounced. In the absence of a regulatory recovery

mechanism for unanticipated costs, such events could influence the Company’s results of operations,

financial conditions or cash flows.

Extreme weather events create a risk of physical damage to the Company’s assets. High winds can

impact structures and cause widespread damage to transmission and distribution infrastructure, solar

generation, and wind powered generation. Higher frequency and severity of weather events increase the

likelihood of longer power outages and more fuel supply disruptions. Increased frequency and intensity of

flooding and storm surge could adversely affect the operations of utilities and in particular generation

assets. The impact of extreme weather events would be amplified if the same events affect multiple

utilities.

Exhibit 99.2

Each of Emera’s regulated electric utilities have programs for storm hardening of transmission and

distribution facilities to minimize damage, but there can be no assurance that these measures will fully

mitigate the risk. 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 designated self-insurance funds, or after the fact through the establishment of regulatory

assets. Recovery is not assured and is subject to prudency review. The risk to generation assets is, in

part, mitigated through the design, siting, construction and maintenance of such facilities, regular risk

assessments, engineered mitigation, emergency storm response plans, and insurance.

High winds and lack of precipitation increase the risk of wildfires resulting from the Company’s

infrastructure or for which the Company may otherwise have responsibility. The risk of wildfires is

addressed primarily through asset management programs for natural gas transmission and distribution

operations, and asset management, storm hardening, and vegetation management programs for electric

utilities, but there can be no assurance that these measures will fully mitigate the risk. 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, they could materially affect Emera’s business, access to capital,

financial condition and results of operations including its reputation with customers, regulators,

governments and financial markets. Resulting costs could include fire suppression costs, regeneration,

timber value, increased insurance costs and costs arising from damages and losses incurred by third

parties.

Changes in Environmental Legislation

Emera is subject to regulation by federal, provincial, state, regional and local authorities regarding

environmental matters, primarily related to its utility operations. This includes laws setting GHG emissions

standards and air emissions standards. Emera is also subject to laws regarding waste management,

wastewater discharges and aquatic and terrestrial habitats.

Changes to GHG emissions standards and air emissions standards could adversely affect Emera’s

operations and financial performance.

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,

reductions in GHG emissions, as well as the goal to phase out coal-fired electricity generation by 2030.

Failure to meet such goals by 2030 could result in material fines, penalties, other sanctions and adverse

reputational impacts. NSPI continues to work with both the provincial and federal governments on

measures to seek to address their carbon reduction goals. Within Emera’s natural gas utilities, there are

ongoing efforts to reduce methane and carbon dioxide emissions through replacement of aging

infrastructure, more efficient operations, operational and supply chain optimization, renewable natural gas

projects, and support of public policy initiatives that address the effects of climate change.

In 2023, the United States Environmental Protection Agency proposed new carbon emission standards

for fossil fuel-fired power plants and the Government of Canada released draft Clean Electricity

Regulations which propose limitations on the use of natural gas generation. Until final rules are issued, it

is not certain what the impact will be on the Company and its operations.

These and other legislative or regulatory changes could influence decisions regarding capital investment,

early retirement of generation facilities and may result in stranded costs if the Company is not able to fully

recover the costs and investment in the affected generation assets. Recovery is not assured and is

subject to prudency review. Legislative or regulatory changes may curtail sales of natural gas to new

customers, which could reduce future customer growth in Emera’s natural gas businesses. Stricter

environmental laws and enforcement of such laws in the future could increase Emera’s exposure to

additional liabilities and costs. These changes could also affect earnings and strategy by changing the

nature and timing of capital investments.

Exhibit 99.2

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.

In addition to imposing continuing compliance obligations, there are permit requirements, laws and

regulations authorizing the imposition of penalties for non-compliance, including fines, injunctive relief,

and other sanctions. The cost of complying with current and future environmental requirements is, and

may be, material to Emera. Failure to comply with environmental requirements or to recover

environmental costs in a timely manner through rates, could have a material adverse effect on Emera. In

addition, Emera’s business could be materially affected by changes in government policy, utility

regulation, and environmental and other legislation that could occur in response to environmental and

climate change concerns.

Emera manages its environmental risk by operating in a manner that is respectful and protective of the

environment and in compliance with applicable legal requirements and Company policy. Emera has

implemented this policy through the development and application of environmental management systems

in its operating subsidiaries. Comprehensive audit programs are in place to regularly assess compliance.

Cybersecurity Risk

Emera is exposed to potential risks related to cyberattacks and unauthorized access. 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 assets, 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.

Cyberattacks can reach the Company’s assets and information via their interfaces with third parties or the

public internet and gain access to 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, or links

in e-mails. The methods used by attackers are continuously evolving and can be difficult to predict and

detect.

Despite security measures in place, that are described below, the Company’s systems, assets and

information could experience security breaches that could cause system failures, disrupt 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, or the release, destruction, or misuse of critical, sensitive or confidential information. These

breaches could also delay delivery or result in contamination or degradation of hydrocarbon products the

Company transports, stores or distributes.

Cyberattacks or unauthorized accesses may cause lost revenues, costs, losses and damages all, or

some of which, may not be recoverable (through insurance, legal, regulatory cost recovery or other

processes). This could materially adversely affect Emera’s business and financial results including its

reputation with customers, regulators, governments and financial markets. 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. If any such security breaches occur,

there is no assurance they can be adequately addressed in a timely manner.

Exhibit 99.2

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.

Public Health Risk

An outbreak of infectious disease, a pandemic or a similar public health threat, or a fear of any of the

foregoing, could adversely impact the Company, including 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 expenditures, results of financing efforts, or credit risk and counterparty risk; which

could result in a material adverse effect on the Company’s business. The Company maintains pandemic

and business contingency plans in each of its operations to manage and help mitigate the impact of any

such public health threat.

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 and battery storage. Government policies promoting 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. The Company’s rate-regulated utilities are focused

on understanding customer demand, energy efficiency, and government policy to ensure that the impact

of these activities benefit customers, that they do not negatively impact the reliability of the energy service

and that they are addressed through regulations.

Foreign Exchange Risk

The Company is exposed to foreign currency exchange rate changes. Emera operates internationally,

with an increasing 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.

Consistent with the Company’s risk management policies, Emera manages currency risks through

matching United States denominated debt to finance its United States 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.

Exhibit 99.2

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”) (“AOCL”).

Liquidity and Capital Market Risk

Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial

obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to

determine whether sufficient funds are available. Liquidity and capital needs could be financed through

internally generated cash flows, asset sales, short-term credit facilities, and ongoing access to capital

markets. The Company reasonably expects liquidity sources to meet capital needs.

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

more information on interest rate risk, refer to “General Economic Risk – Interest Rate Risk”. 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. Emera manages

these risks by actively monitoring and managing key financial metrics with the objective of sustaining

investment grade credit ratings.

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 materially affect Emera and its utilities. 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.

Exhibit 99.2

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. Emera seeks to manage interest rate risk

through a portfolio approach that includes the use of fixed and floating rate debt with staggered

maturities. The Company will, from time to time, issue long-term debt or enter interest rate hedging

contracts to limit its exposure to fluctuations in floating interest rate debt.

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 Market 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. Emera’s utilities have budgeting and forecasting processes to identify inflationary risk factors and

measure operating performance, as well as collective bargaining agreements that mitigate the short-term

impact of inflation on labour costs of unionized employees.

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 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.

Emera manages these project development and land use rights risks by deploying robust project and risk

management approaches, led by teams with extensive experience in large projects. The Company

consults with Indigenous Peoples in obtaining approvals, constructing, maintaining and operating such

facilities, consistent with laws and public policy frameworks. Emera maintains relationships through on-

going communications with stakeholders, including Indigenous Peoples, landowners and governments.

Exhibit 99.2

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.

Emera manages this counterparty risk through due diligence and third-party risk assessment processes

prior to signing contracts, contractual rights and remedies, regulatory frameworks, and by monitoring

significant developments with its customers, partners and suppliers. The Company also manages credit

risk with policies and procedures for counterparty analysis, exposure measurement, and exposure

monitoring and mitigation. Credit assessments may be conducted on new customers and counterparties,

and deposits or collateral may be requested on certain accounts. There is no assurance that

management strategies will be effective,

and significant counterparty defaults could have a material effect

on the Company.

Country Risk

The majority of Emera’s earnings are from outside of Canada, mostly concentrated in the United States.

Emera’s investments are currently in regions where political and economic risks are considered by the

Company to be acceptable. For more information, refer to the “Regulatory and Political Risk” and

“General Economic Risk” sections above. Emera’s operations in some countries may be subject to

changes in economic growth, restrictions on the repatriation of income or capital exchange controls,

inflation, the effect of global health, safety and environmental matters, including climate change, or

economic conditions and market conditions, and change in financial policy and availability of credit. The

Company mitigates this risk through a rigorous approval process for investment, and by forecasting cash

requirements on a continuous basis to determine whether sufficient funds are available in all affiliates.

Supply Chain Risk

Emera’s ability to meet customer energy requirements, respond to storm-related disruptions and execute

on our capital 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 or result in shortages of

certain materials, equipment and other resources that are critical to the Company’s operations. These

disruptions may be further exacerbated by inflationary pressures, labour shortages, government

incentives increasing demand for clean energy projects, and the impact of international conflicts, tariffs, or

other trade restrictions. 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.

Emera continues to monitor the situation and seeks to mitigate the impacts of supply chain risk by

securing alternative suppliers, third party risk management, modifying design standards, and adjusting

the timing of work.

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.

Exhibit 99.2

The Company manages this risk through established processes and practices to identify, monitor, report

and mitigate these risks. These include the Company’s commercial arrangements, such as the

combination of supply and purchase agreements, asset management agreements, pipeline transportation

agreements, and financial hedging instruments. In addition, its credit policies, counterparty credit

assessments, market and credit position reporting, and other risk management and reporting practices,

are also used to manage and mitigate this risk.

Regulated Utilities:

The Company’s utility fuel supply is exposed to broader global 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, trade sanctions or embargos. The Company seeks to manage

this risk using financial hedging instruments and physical contracts and through contractual protection

with counterparties, where applicable.

The majority of Emera’s regulated electric and gas utilities have adopted and implemented fuel

adjustment mechanisms and purchased gas adjustment mechanisms respectively, which further helps

manage commodity price risk, as the regulatory framework for the Company’s rate-regulated subsidiaries

permits the recovery of prudently incurred fuel and gas costs. There is no assurance that such

mechanisms and regulatory frameworks will continue to exist in the future. 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.

Emera Energy Marketing and Trading:

Emera Energy has employed further measures to manage commodity risk. 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 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.

measure commodity price risk exposure, Emera Energy employs a number of controls and processes,

including an estimated VaR analysis of its exposures. The VaR

amount represents an estimate of the

potential change in FV that could occur from changes in Emera Energy’s portfolio or changes in market

factors within a given confidence level, if an instrument or portfolio is held for a specified time period. The

VaR calculation is used to quantify exposure to market risk associated with physical commodities,

primarily natural gas and power positions.

Future Employee Benefit Plan Performance and Funding Risk

Emera subsidiaries have both defined benefit and defined contribution employee pension plans that cover

their employees and retirees. All defined benefit plans are closed to new entrants, except for the TECO

Energy 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. Three of the 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 adversely affect Emera’s cash flows, financial condition and operations.

Exhibit 99.2

Each of Emera’s employee defined benefit pension plans are managed according to an approved

investment policy and governance framework. Emera employs a long-term approach with respect to asset

allocation and each investment policy outlines the level of risk which the Company is prepared to accept

with respect to the investment of the pension funds in achieving both the Company’s fiduciary and

financial objectives. Studies are routinely undertaken approximately every five years with the objective

that the plans’ asset allocations are appropriate for meeting Emera’s long-term pension objectives.

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

adversely affect the Company’s operations and financial results. Emera seeks to manage this risk through

maintaining competitive compensation programs, a dedicated talent acquisition team, human resources

programs and practices, including ethics and diversity training, employee engagement surveys,

succession planning for key positions and apprenticeship programs.

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 an adverse effect on the Company’s earnings, cash flow and financial position. Emera seeks to

manage this risk through ongoing discussions and working to maintain positive relationships with local

unions. The Company maintains contingency plans in each of its operations to manage and reduce the

effect of any potential labour disruption.

IT Risk

Emera relies on various IT systems to manage operations. 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.

Emera manages these risks through IT asset lifecycle planning and management, governance, internal

auditing and testing of systems, and executive oversight. Employees with extensive subject matter

expertise assist in risk identification and mitigation, project management, implementation, change

management and training. System resiliency, formal disaster recovery and backup processes, combined

with critical incident response practices, table-top exercises, and simulations, help mitigate operational

disruptions.

Income Tax Risk

The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in

Canada, the United States and the Caribbean. Any such changes could affect the Company’s future

earnings, cash flows, and financial position. 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.

Emera monitors the status of existing tax laws to ensure that changes impacting the Company are

appropriately reflected in the Company’s tax compliance filings and financial results.

Exhibit 99.2

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, damage to facilities, solar panels 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. Refer to “Global Climate Change Risk” and

“Weather Risk”. Electric utility and natural gas transmission and distribution pipeline operation interruption

could negatively affect revenue, earnings, and cash flows as well as customer and public confidence, and

public safety.

Emera manages these risks by investing in a highly skilled workforce, operating prudently, preventative

maintenance, safety and operations management systems, third-party risk program, and making effective

capital investments. Insurance, warranties, or recovery through regulatory mechanisms may not cover

any or all these losses, which could adversely affect the Company’s results of operations and cash flows.

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. The risk of fuel supply disruptions is managed

through contractual protections, maintaining a diversity of fuel suppliers and transportation contracts, and

contracting for access to third-party storage 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 adverse effects on service to utility customers and on the

Company’s reputation, earnings, cash flow and financial position.

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. This is consistent with Emera’s risk management

policies. Certain facilities, in particular coal and other thermal generation, may, over time, become more

difficult (or uneconomic) to insure as a result of the impact of global climate change. Refer to “Global

Climate Change Risk – Markets”. There are certain elements of Emera’s operations which are not

insured. These include a significant portion of its electric utilities’ transmission and distribution assets and

its gas utilities’ distribution assets, as is customary in the industry. The cost of this coverage is not

economically viable. 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 by the Company and its subsidiaries will be covered by insurance.

The occurrence of significant uninsured claims, claims in excess of the insurance coverage limits

maintained by Emera and its subsidiaries, or claims that fall within a significant self-insured retention

could have a material adverse effect on Emera’s results of operations, cash flows and financial position, if

regulatory recovery is not available.

The Company manages its insured risk by aligning insurance limits with risk exposures, and for uninsured

assets and operations, that appropriate risk assessments and mitigation measures are in place. The

regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently

incurred costs, including uninsured losses.

Exhibit 99.2

RISK MANAGEMENT INCLUDING FINANCIAL

INSTRUMENTS

Emera’s risk management policies and procedures provide a framework through which management

monitors various risk exposures. Risk management policies and practices are overseen by the Board.

The Company has established a number of processes and practices to identify, monitor, report on and

mitigate material risks to the Company. This includes establishment of the ERMC, whose responsibilities

include preparing an updated risk dashboard and heat map presented at regular meetings of the Board’s

Risk and Sustainability Committee. Furthermore, a corporate team independent from operations is

responsible for tracking and reporting on market and credit risks.

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 has no derivatives related to hedging as a result of a

FPSC approved five-year moratorium on hedging of natural gas purchases that ended on December 31,

2022 and was extended through December 31, 2024 as a result of TEC’s 2021 rate case settlement

agreement.

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.

Exhibit 99.2

Derivative Assets and Liabilities Recognized on the Balance Sheet

As at

December 31

millions of dollars

2023

2022

Regulatory Deferral:

Derivative instrument assets

(1)

238

Derivative instrument liabilities

(2)

(76)

(25)

Regulatory assets

(1)

Regulatory liabilities

(2)

(17)

(230)

Net asset

HFT Derivatives:

Derivative instrument assets

(1)

202

153

Derivatives instruments liabilities

(2)

(421)

(1,025)

Net liability

(219)

(872)

Other Derivatives:

Derivative instrument assets

(1)

Derivatives instruments liabilities

(2)

(7)

(28)

Net asset (liability)

(23)

(1) Current and other assets.

(2) Current and long-term liabilities.

Realized and Unrealized Gains (Losses) Recognized in Net Income

For the

Year ended December 31

millions of dollars

2023

2022

Regulatory Deferral:

Regulated fuel for generation and purchased power

(1)

210

HFT Derivatives:

Non-regulated operating revenues

1,037

Other Derivatives:

OM&G

(9)

(22)

Other income, net

(24)

Net gains (losses)

(46)

Total net gains

1,107

228

(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.

For the year ended December 31, 2023, unrealized gains of $2 million (2022 – $2 million), have been

reclassified out of AOCI into interest expense.

As at

December 31, 2023

December 31, 2022

Interest rate

millions of dollars

hedge

Total unrealized gain in AOCI – net of tax

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, 2023 to

provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.

Exhibit 99.2

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, 2023, 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, 2023, the Company had recorded $3,105 million (2022 – $3,620 million) of regulatory

assets and $1,772 million (2022 – $2,273 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, 2023, the balance of the Accumulated reserve – COR

within regulatory liabilities was $849 million (2022 – $895 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.

Exhibit 99.2

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 8.0 years (8.4 years for 2023 benefit cost) for Canadian plans and a

weighted average of 11.5 years for United States 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:

2023

2022

Discount rate for

benefit cost

purposes

Expected

return on

plan assets

Discount rate for

benefit cost

purposes

Expected

return on

plan assets

TECO Energy Group Retirement Plan

5.55%

7.05%

2.78%

6.50%

TECO Energy Group Supplemental

Executive Retirement Plan

(1)

5.45%/5.31%

N/A

2.35/5.33%

N/A

TECO Energy Group Benefit

Restoration Plan (1)

5.48/5.30/5.49%

N/A

2.27/4.19/5.48%

N/A

TECO Energy Post-retirement Health

and Welfare Plan

5.53%/6.14%

N/A

2.84%

N/A

New Mexico Gas Company Retiree

Medical Plan

5.55%

2.50%

2.85%

1.50%

NSPI

5.17%, 5.19%

6.25%

3.25%, 3.48%

5.75%

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 $43 million in 2023 (2022 – $64 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 2023 benefit cost of $0.5

million and $2.5 million, respectively (2022 – $0.5 million and $1 million).

Exhibit 99.2

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, 2023,

unbilled revenues totalled $363 million (2022 – $424 million) on total regulated operating revenues of

$7,235 million (2022 – $7,154 million).

PP&E

PP&E represents 62 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 $1,019 million for the year ended December 31, 2023 (2022 – $927 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.

Exhibit 99.2

As of December 31, 2023, $5,868 million (2022 – $6,009 million) of Emera’s goodwill represents the

excess of the acquisition purchase price for TECO Energy (TEC, PGS and NMGC reporting units) over

the FV assigned to identifiable assets acquired and liabilities assumed. In Q4 2023, qualitative

assessments were performed for NMGC and PGS, given the significant excess of FV over carrying

amounts calculated during the last quantitative tests in Q4 2022 and Q4 2019, respectively. Management

concluded it was more likely than not that the FV of these reporting units exceeded their respective

carrying amounts, including goodwill. As such, no quantitative testing was required. Given the length of

time passed since the last quantitative impairment test for the TEC reporting unit, Emera elected to

bypass a qualitative assessment and performed a quantitative impairment assessment in Q4 2023 using

a combination of the income and market approach. This assessment estimated that the FV of the TEC

reporting unit exceeded its carrying amount, including goodwill, and as a result no impairment charges

were recognized.

As of December 31, 2023, the Company had goodwill with a total carrying amount of $5,871 million

(December 31, 2022 – $6,012 million). The change in the carrying value of goodwill from 2022 to 2023

was a result of the effect of the FX translation of Emera’s foreign affiliates.

In Q4 2022, as a result of a quantitative assessment, the Company recorded a goodwill impairment

charge of $73 million, reducing the GBPC goodwill balance to nil as at December 31, 2022. For further

detail, refer to note 22 in the consolidated financial statements.

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.

As at December 31, 2023, there were no indications of impairment of Emera’s long-lived assets. No

impairment charges were recognized in either 2023 or 2022.

Exhibit 99.2

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, 2023, AROs recorded on the balance sheet were $192 million (2022 – $174 million).

The Company estimates the undiscounted amount of cash flow required to settle the obligations is

approximately $426 million (2022 – $429 million), which will be incurred between 2023 and 2061. The

majority of these costs will be incurred between 2028 and 2050.

Exhibit 99.2

Financial Instruments

The Company is required to determine the FV of all derivatives except those that qualify for the normal

purchase, normal sale 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

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.

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, and

interim periods within annual reporting periods beginning after December 15, 2025. 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.

Exhibit 99.2

Improvements to Reportable Segment Disclosures

In November 2023, the FASB issued 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 will be effective for annual reporting periods beginning after December 15, 2023, and for

interim periods beginning after December 15, 2024. Early adoption is permitted. The standard will be

applied retrospectively. The Company is currently evaluating the impact of adoption of the standard on its

consolidated financial statements.

SUMMARY OF QUARTERLY

RESULTS

For the quarter ended

millions of dollars

(except per share amounts)

2023

2022

Operating revenues

1,972

1,740

1,418

2,433

2,358

1,835

1,380

2,015

Net income (loss) attributable to

common shareholders

289

101

560

483

167

(67)

362

Adjusted net income

175

204

162

268

249

203

156

242

EPS – basic

1.04

0.37

0.10

2.07

1.80

0.63

(0.25)

1.38

EPS – diluted

1.04

0.37

0.10

2.07

1.80

0.63

(0.25)

1.38

Adjusted EPS – basic

0.63

0.75

0.60

0.99

0.93

0.76

0.59

0.92

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.