EX-99.3

Exhibit 99.3

EMERA INCORPORATED

Consolidated

Financial Statements

December 31, 2023 and 2022

Exhibit 99.3

MANAGEMENT REPORT

Management's Responsibility for Financial Reporting

The accompanying consolidated financial statements of Emera Incorporated and the information in this

annual report are the responsibility of management and have been approved by the Board of Directors

(“Board”).

The consolidated financial statements have been prepared by management in accordance with United

States Generally Accepted Accounting Principles. When alternative accounting methods exist,

management has chosen those it considers most appropriate in the circumstances. In preparation of

these consolidated financial statements, estimates are sometimes necessary when transactions affecting

the current accounting period cannot be finalized with certainty until future periods. Management

represents that such estimates, which have been properly reflected in the accompanying consolidated

financial statements, are based on careful judgments and are within reasonable limits of materiality.

Management has determined such amounts on a reasonable basis in order to ensure that the

consolidated financial statements are presented fairly in all material respects. Management has prepared

the financial information presented elsewhere in the annual report and has ensured that it is consistent

with that in the consolidated financial statements.

Emera Incorporated maintains effective systems of internal accounting and administrative controls,

consistent with reasonable cost. Such systems are designed to provide reasonable assurance that the

financial information is reliable and accurate, and that Emera Incorporated's assets are appropriately

accounted for and adequately safeguarded.

The Board is responsible for ensuring that management fulfils its responsibilities for financial reporting

and is ultimately responsible for reviewing and approving the consolidated financial statements. The

Board carries out this responsibility principally through its Audit Committee.

The Audit Committee is appointed by the Board, and its members are directors who are not officers or

employees of Emera Incorporated. The Audit Committee meets periodically with management, as well as

with the internal auditors and with the external auditors, to discuss internal controls over the financial

reporting process, auditing matters and financial reporting issues, to satisfy itself that each party is

properly discharging its responsibilities, and to review the annual report, the consolidated financial

statements and the external auditors' report. The Audit Committee reports its findings to the Board for

consideration when approving the consolidated financial statements for issuance to the shareholders.

The Audit Committee also considers, for review by the Board and approval by the shareholders, the

appointment of the external auditors.

The consolidated financial statements have been audited by Ernst & Young LLP,

the external auditors, in

accordance with Canadian Generally Accepted Auditing Standards and with the standards of the Public

Company Accounting Oversight Board. Ernst & Young LLP has full and free access to the Audit

Committee.

February 26, 2024

“Scott Balfour”

“Gregory Blunden”

President and Chief Executive Officer

Chief Financial Officer

Exhibit 99.3

Report of Independent Registered Public Accounting Firm

the Shareholders and the Board of Directors of Emera Incorporated

Opinion on the Consolidated Financial Statements

We have audited the accompanying Consolidated Balance Sheets of Emera Incorporated (the

“Company“) as of December 31, 2023 and 2022, the related Consolidated Statements of Income,

Consolidated Statements of Comprehensive Income, Consolidated Statements of Changes in Equity and

Consolidated Statements of Cash Flows for the years then ended, and the related notes (collectively

referred to as the “consolidated financial statements“). In our opinion, the consolidated financial

statements present fairly, in all material respects, the consolidated financial position of the Company as of

December 31, 2023 and 2022, and the consolidated results of its operations and its consolidated cash

flows for each of the two years in the period ended December 31, 2023, in conformity with United States

generally accepted accounting principles.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company‘s management. Our

responsibility is to express an opinion on the Company‘s consolidated financial statements based on our

audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board

(United States) (“PCAOB”) and are required to be independent with respect to the Company in

accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities

and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that

we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial

statements are free of material misstatement, whether due to error or fraud. The Company is not required

to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part

of our audits we are required to obtain an understanding of internal control over financial reporting but not

for the purpose of expressing an opinion on the effectiveness of the Company's internal control over

financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the

consolidated financial statements, whether due to error or fraud, and performing procedures that respond

to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and

disclosures in the consolidated financial statements. Our audits also included evaluating the accounting

principles used and significant estimates made by management, as well as evaluating the overall

presentation of the consolidated financial statements. We believe that our audits provide a reasonable

basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the

financial statements that were communicated or required to be communicated to the audit committee and

that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our

especially challenging, subjective or complex judgments. The communication of critical audit matters

does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we

are not, by communicating the critical audit matters below, providing separate opinions on the critical

audit matters or on the accounts or disclosures to which they relate.

Exhibit 99.3

Accounting for the effects of rate regulation

Description of the

Matter

As disclosed in note 6 of the consolidated financial statements, the

Company has $3.1 billion in regulatory assets and $1.8 billion in regulatory

liabilities. The Company’s rate-regulated subsidiaries are subject to

regulation by various federal, state and provincial regulatory authorities in

the geographic regions in which they operate. The regulatory rates are

designed to recover the prudently incurred costs of providing the regulated

products or services and provide a reasonable return on the equity invested

or assets, as applicable. In addition to regulatory assets and liabilities, rate

regulation impacts multiple financial statement line items, including, but not

limited to, property, plant and equipment (“PP&E”), operating revenues and

expenses, income taxes, and depreciation expense.

Auditing the impact of rate regulation on the Company’s financial

statements is complex and highly judgmental due to the significant

judgments made by the Company to support its accounting and disclosure

for regulatory matters when final regulatory decisions or orders have not yet

been obtained or when regulatory formulas are complex. There is also

subjectivity involved in assessing the potential impact of future regulatory

decisions on the financial statements. Although the Company expects to

recover costs from customers through rates, there is a risk that the regulator

will not approve full recovery of the costs incurred. The Company’s

judgments include making an assessment of the probability of recovery of

and return on costs incurred, of the potential disallowance of part of the cost

incurred, or of the probable refund of gains or amounts previously collected

from customers through future rates.

How We Addressed

the Matter in Our

Audit

We performed audit procedures that included, amongst others, assessing

the Company’s evaluation of the probability of future recovery for regulatory

assets, PP&E, and refund of regulatory liabilities by obtaining and reviewing

relevant regulatory orders, filings, testimony, hearings and correspondence,

and other publicly available information. For regulatory matters for which

regulatory decisions or orders have not yet been obtained, we inspected the

rate-regulated subsidiaries’ filings for any evidence that might contradict the

Company’s assertions, and reviewed other regulatory orders, filings and

correspondence for other entities within the same or similar jurisdictions to

assess the likelihood of recovery or refund in future rates based on the

regulator’s treatment of similar costs under similar circumstances. We

obtained and evaluated an analysis from the Company and corroborated

that analysis with letters from legal counsel, when appropriate, regarding

cost recoveries, gains or amounts previously collected from customers or

future changes in rates. We also assessed the methodology, accuracy and

completeness of the Company’s calculations of regulatory asset and liability

balances based on provisions and formulas outlined in rate orders and

other correspondence with the regulators. We evaluated the Company's

disclosures related to the impacts of rate regulation.

Fair Value (“FV”) measurement of derivative financial

instruments

Description of the

Matter

Held-for-trading (“HFT”) derivative assets of $348 million and liabilities of

$567 million, disclosed in note 15 to the consolidated financial statements,

are measured at FV. The Company recognized $1,037 million in realized

and unrealized gains during the year with respect to HFT derivatives.

Exhibit 99.3

Auditing the Company’s valuation of HFT derivatives is complex and highly

judgmental due to the complexity of the contract terms and valuation

models, and the significant estimation required in determining the FV of the

contracts. In determining the FV of HFT derivatives, significant assumptions

about future economic and market assumptions with uncertain outcomes

are used, including third-party sourced forward commodity pricing curves

based on illiquid markets, internally developed correlation factors and basis

differentials. These assumptions have a significant impact on the FV of the

HFT derivatives.

How We Addressed

the Matter in Our

Audit

We performed audit procedures that included, amongst others, reviewing

executed contracts and agreements for the identification of inputs and

assumptions impacting the valuation of derivatives. With the support of our

valuation specialists, we assessed the methodology and mathematical

accuracy of the Company’s valuation models and compared the commodity

pricing curves used by the Company to current market and economic data.

For the forward commodity pricing curves, we compared the Company’s

pricing curves to independently sourced pricing curves. We also assessed

the methodology and mathematical accuracy of the Company’s calculations

to develop correlation factors and basis differentials. In addition, we

assessed whether the FV hierarchy disclosures in note 16 to the

consolidated financial statements were consistent with the source of the

significant inputs and assumptions used in determining the FV of

derivatives.

/s/

Ernst & Young LLP

Chartered Professional Accountants

We have served as the Company‘s auditor since 1998.

Halifax, Canada

February 26, 2024

Exhibit 99.3

Emera Incorporated

Consolidated Statements of Income

For the

Year ended December 31

millions of dollars (except per share amounts)

2023

2022

Operating revenues

Regulated electric

5,746

5,473

Regulated gas

1,489

1,681

Non-regulated

328

434

Total operating revenues (note 5)

7,563

7,588

Operating expenses

Regulated fuel for generation and purchased power

1,881

2,171

Regulated cost of natural gas

527

800

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

1,879

1,596

Provincial, state, and municipal taxes

433

367

Depreciation and amortization

1,049

952

GBPC Impairment charge (note 22)

Total operating expenses

5,769

5,959

Income from operations

1,794

1,629

Income from equity investments (note 7)

146

129

Other income, net (note 8)

158

145

Interest expense, net (note 9)

925

709

Income before provision for income taxes

1,173

1,194

Income tax expense (note 10)

128

185

Net income

1,045

1,009

Non-controlling interest in subsidiaries

Preferred stock dividends

Net income attributable to common shareholders

978

945

Weighted average shares of common stock outstanding (in millions) (note 12)

Basic

274

266

Diluted

274

266

Earnings per common share (note 12)

Basic

3.57

3.56

Diluted

3.57

3.55

Dividends per common share declared

2.7875

2.6775

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

Exhibit 99.3

Emera Incorporated

Consolidated Statements of Comprehensive Income

For the

Year ended December 31

millions of dollars

2023

2022

Net income

1,045

1,009

Other comprehensive (loss) income, net of tax

Foreign currency translation adjustment

(1)

(270)

629

Unrealized gains (losses) on net investment hedges

(2) (3)

(97)

Cash flow hedges – reclassification adjustment for gains included in income

(4)

(2)

Unrealized losses on available-for-sale investment

(1)

Net change in unrecognized pension and post-retirement benefit obligation

(5)

(39)

Other comprehensive (loss) income

(6)

(273)

553

Comprehensive income

772

1,562

Comprehensive income attributable to non-controlling interest

Comprehensive Income of Emera Incorporated

771

1,561

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

1) Net of tax recovery of $7 million for the year ended December 31, 2023 (2022 – $

million expense).

2) The Company has designated $

1.2

billion United States dollar (USD) denominated Hybrid Notes as a hedge of the foreign

currency exposure of its net investment in USD denominated operations.

3) Net of tax expense of nil for the year ended December 31, 2023 (2022 – $6 million recovery).

4) Net of tax expense of nil for the year ended December 31, 2023 (2022 – $1 million recovery).

5) Net of tax expense of $

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

million expense).

6) Net of tax recovery of $6 million for the year ended December 31, 2023 (2022 – $

million expense).

Exhibit 99.3

Emera Incorporated

Consolidated Balance Sheets

As at

December 31

millions of dollars

2023

2022

Assets

Current assets

Cash and cash equivalents

567

310

Restricted cash (note 32)

Inventory (note 14)

790

769

Derivative instruments (notes 15 and 16)

174

296

Regulatory assets (note 6)

339

602

Receivables and other current assets (note 18)

1,817

2,897

3,708

4,896

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

net of accumulated depreciation

and amortization of $

9,994

and $

9,574

, respectively (note 20)

24,376

22,996

Other assets

Deferred income taxes (note 10)

208

237

Derivative instruments (notes 15 and 16)

100

Regulatory assets (note 6)

2,766

3,018

Net investment in direct finance and sales type leases (note 19)

621

604

Investments subject to significant influence (note 7)

1,402

1,418

Goodwill (note 22)

5,871

6,012

Other long-term assets (note 32)

462

461

11,396

11,850

Total assets

39,480

39,742

Liabilities and Equity

Current liabilities

Short-term debt (note 23)

1,433

2,726

Current portion of long-term debt (note 25)

676

574

Accounts payable

1,454

2,025

Derivative instruments (notes 15 and 16)

386

888

Regulatory liabilities (note 6)

168

495

Other current liabilities (note 24)

427

579

4,544

7,287

Long-term liabilities

Long-term debt (note 25)

17,689

15,744

Deferred income taxes (note 10)

2,352

2,196

Derivative instruments (notes 15 and 16)

118

190

Regulatory liabilities (note 6)

1,604

1,778

Pension and post-retirement liabilities (note 21)

265

281

Other long-term liabilities (note 7 and 26)

820

825

22,848

21,014

Equity

Common stock (note 11)

8,462

7,762

Cumulative preferred stock (note 28)

1,422

Contributed surplus

Accumulated other comprehensive income ("AOCI') (note 13)

305

578

Retained earnings

1,803

1,584

Total Emera Incorporated equity

12,074

11,427

Non-controlling interest in subsidiaries (note 29)

Total equity

12,088

11,441

Total liabilities and equity

39,480

39,742

Commitments and contingencies (note 27)

Approved on behalf of the Board of Directors

The accompanying notes are an integral part of

“M. Jacqueline Sheppard”

“Scott Balfour”

these consolidated financial statements.

Chair of the Board

President and Chief Executive Officer

Exhibit 99.3

Emera Incorporated

Consolidated Statements of Cash Flows

For the

Year ended December 31

millions of dollars

2023

2022

Operating activities

Net income

1,045

1,009

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

Depreciation and amortization

1,060

959

Income from equity investments, net of dividends

(22)

(61)

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

(38)

(52)

Deferred income taxes, net

152

Net change in pension and post-retirement liabilities

(68)

(48)

NSPI Fuel adjustment mechanism ("FAM")

(88)

(162)

Net change in Fair Value ("FV") of derivative instruments

(666)

206

Net change in regulatory assets and liabilities

554

(471)

Net change in capitalized transportation capacity

434

(445)

GBPC impairment charge

Other operating activities, net

(13)

Changes in non-cash working capital (note 30)

(95)

(234)

Net cash provided by operating activities

2,241

913

Investing activities

Additions to PP&E

(2,937)

(2,596)

Other investing activities

Net cash used in investing activities

(2,917)

(2,569)

Financing activities

Change in short-term debt, net

(66)

1,028

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

548

544

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

(1,086)

(680)

Proceeds from long-term debt, net of issuance costs

1,932

784

Retirement of long-term debt

(151)

(367)

Net (repayments) proceeds under committed credit facilities

(96)

511

Issuance of common stock, net of issuance costs

424

277

Dividends on common stock

(488)

(472)

Dividends on preferred stock

(66)

(63)

Other financing activities

(12)

(7)

Net cash provided by financing activities

939

1,555

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

(7)

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

256

(85)

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

332

417

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

588

332

Cash, cash equivalents, and restricted cash consists of:

Cash

559

302

Short-term investments

Restricted cash

Cash, cash equivalents, and restricted cash

588

332

Supplementary Information to Consolidated Statements of Cash Flows (note 30)

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

Exhibit 99.3

Emera Incorporated

Consolidated Statements of Changes in Equity

Non-

Common

Preferred

Contributed

Retained

Controlling

Total

Stock

Surplus

AOCI

Earnings

Interest

Equity

millions of dollars

Balance, December 31, 2022

7,762

1,422

578

1,584

11,441

Net income of Emera Inc.

1,044

1,045

Other comprehensive loss, net of tax

recovery of $

million

(273)

Dividends declared on preferred stock

(note 28)

(66)

Dividends declared on common stock

2.7875

/share)

(759)

Issued under the at-the-market

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

issuance costs

397

Issued under the Dividend

Reinvestment Program ("DRIP"), net of

discount

272

Senior management stock options

exercised and Employee Common

Share Purchase Plan ("ECSPP")

Other

(1)

Balance, December 31, 2023

8,462

1,422

305

1,803

12,088

Balance, December 31, 2021

7,242

1,422

1,348

10,150

Net income of Emera Inc.

1,008

1,009

Other comprehensive income, net of tax

expense of $

million

553

Dividends declared on preferred stock

(note 28)

(63)

Dividends declared on common stock

2.6775

/share)

(709)

Issued under the ATM, net of after-tax

issuance costs

248

Issued under the DRIP,

net of discount

238

Senior management stock options

exercised and ECSPP

Disposal of non-controlling interest of

Dominica Electricity Services Ltd

("Domlec")

(20)

Other

(1)

Balance, December 31, 2022

7,762

1,422

578

1,584

11,441

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

Exhibit 99.3

Emera Incorporated

Notes to the Consolidated Financial Statements

As at December 31, 2023 and 2022

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in

electricity generation, transmission and distribution, and gas transmission and distribution.

At December 31, 2023, Emera’s reportable segments include the following:

●

Florida Electric Utility, which consists of Tampa

Electric (“TEC”), a vertically integrated regulated

electric utility, serving approximately

840,000

customers in West Central Florida;

●

Canadian Electric Utilities, which includes:

●

Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated electric utility and the

primary electricity supplier in Nova Scotia, serving approximately

549,000

customers; and

●

Emera Newfoundland & Labrador Holdings Inc. (“ENL”), consisting of two transmission

investments related to an

824

megawatt (“MW”) hydroelectric generating facility at Muskrat

Falls on the Lower Churchill River in Labrador, developed by Nalcor Energy.

ENL’s two

investments are:

●

100

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

the Maritime Link Project, a $

1.8

billion transmission project, including AFUDC; and

●

per cent equity interest in the partnership capital of Labrador-Island Link Limited

Partnership (“LIL”), a $

3.7

billion electricity transmission project in Newfoundland and

Labrador.

●

Gas Utilities and Infrastructure, which includes:

●

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

490,000

customers across Florida. Effective January 1, 2023, Peoples Gas System ceased

to be a division of Tampa

Electric Company 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.;

●

New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility,

serving

approximately

540,000

customers in New Mexico;

●

Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a

145

-kilometre pipeline

delivering re-gasified liquefied natural gas from Saint John, New Brunswick to the United

States border under a

-year firm service agreement with Repsol Energy North America

Canada Partnership (“Repsol Energy”), which expires in 2034;

●

SeaCoast Gas Transmission, LLC (“SeaCoast”), a regulated intrastate natural gas

transmission company offering services in Florida; and

●

12.9

per cent equity interest in Maritimes & Northeast Pipeline (“M&NP”), a

1,400

-kilometre

pipeline that transports natural gas throughout markets in Atlantic Canada and the

northeastern United States.

●

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

with regulated electric utilities that include:

●

The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated regulated

electric utility on the island of Barbados, serving approximately

134,000

customers;

●

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

utility on Grand Bahama Island, serving approximately

19,000

customers; and

●

19.5

per cent equity interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically

integrated regulated electric utility on the island of St. Lucia.

Exhibit 99.3

●

Emera’s other reportable segment includes investments in energy-related non-regulated companies

which include:

●

Emera Energy, which consists of:

●

Emera Energy Services (“EES”), a physical energy business that purchases and sells

natural gas and electricity and provides related energy asset management services;

●

Brooklyn Power Corporation (“Brooklyn Energy”), a

MW biomass co-generation

electricity facility in Brooklyn, Nova Scotia; and

●

50.0

per cent joint venture interest in Bear Swamp Power Company LLC (“Bear

Swamp”), a

660

MW pumped storage hydroelectric facility in northwestern

Massachusetts.

●

Emera US Finance LP (“Emera Finance”) and TECO Finance, Inc. (“TECO Finance”),

financing subsidiaries of Emera;

●

Block Energy LLC (previously Emera Technologies LLC), a wholly owned technology

company focused on finding ways to deliver renewable and resilient energy to customers;

●

Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets

located in the United States; and

●

Other investments.

Basis of Presentation

These consolidated financial statements are prepared and presented in accordance with United States

Generally Accepted Accounting Principles (“USGAAP”) and in the opinion of management, include all

adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera.

All dollar amounts are presented in Canadian dollars (“CAD”), unless otherwise indicated.

Principles of Consolidation

These consolidated financial statements include the accounts of Emera Incorporated, its majority-owned

subsidiaries, and a variable interest entity (“VIE”) in which Emera is the primary beneficiary. Emera uses

the equity method of accounting to record investments in which the Company has the ability to exercise

significant influence, and for VIEs in which Emera is not the primary beneficiary.

The Company performs ongoing analysis to assess whether it holds any VIEs or whether any

reconsideration events have arisen with respect to existing VIEs. To identify potential VIEs, management

reviews contractual and ownership arrangements such as leases, long-term purchase power agreements,

tolling contracts, guarantees, jointly owned facilities and equity investments. VIEs of which the Company

is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the

power to direct the activities of the VIE that most significantly impacts its economic performance and the

obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to

the VIE. In circumstances where Emera has an investment in a VIE but is not deemed the primary

beneficiary, the VIE is accounted for using the equity method. For further details on VIEs, refer to note 32.

Intercompany balances and transactions have been eliminated on consolidation, except for the net profit

on certain transactions between certain non-regulated and regulated entities in accordance with

accounting standards for rate-regulated entities. The net profit on these transactions, which would be

eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non-

regulated operating revenues. An offset is recorded to PP&E, regulatory assets, regulated fuel for

generation and purchased power, or OM&G, depending on the nature of the transaction.

Exhibit 99.3

Use of Management Estimates

The preparation of consolidated financial statements in accordance with USGAAP requires management

to make estimates and assumptions. These may affect reported amounts of assets and liabilities at the

date of the financial statements and reported amounts of revenues and expenses during the reporting

periods. Significant areas requiring use of management estimates relate to rate-regulated assets and

liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled

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

income taxes, asset retirement obligations (“ARO”), and valuation of financial instruments. Management

evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and

expected conditions and assumptions believed to be reasonable at the time the assumption is made, with

any adjustments recognized in income in the year they arise.

Regulatory Matters

Regulatory accounting applies where rates are established by, or subject to approval by, an

independent

third-party regulator. Rates are designed to recover prudently incurred costs of providing regulated

products or services and provide an opportunity for a reasonable rate of return on invested capital, as

applicable. For further detail, refer to note 6.

Foreign Currency Translation

Monetary assets and liabilities denominated in foreign currencies are converted to CAD at the rates of

exchange prevailing at the balance sheet date. The resulting differences between the translation at the

original transaction date and the balance sheet date are included in income.

Assets and liabilities of foreign operations whose functional currency is not the Canadian dollar are

translated using exchange rates in effect at the balance sheet date and the results of operations at the

average exchange rate in effect for the period. The resulting exchange gains and losses on the assets

and liabilities are deferred on the balance sheet in AOCI.

The Company designates certain USD denominated debt held in CAD functional currency companies as

hedges of net investments in USD denominated foreign operations. The change in the carrying amount of

these investments, measured at exchange rates in effect at the balance sheet date is recorded in Other

Comprehensive Income (“OCI”).

Revenue Recognition

Regulated Electric and Gas Revenue:

Electric and gas revenues, including energy charges, demand charges, basic facilities charges and

clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is

when electricity and gas are delivered to customers over time as the customer simultaneously receives

and consumes the benefits. Electric and gas revenues are recognized on an accrual basis and include

billed and unbilled revenues. Revenues related to the sale of electricity and gas are recognized at rates

approved by the respective regulators and recorded based on metered usage, which occurs on a

periodic, systematic basis, generally monthly or bi-monthly. At the end of each reporting period, electricity

and gas delivered to customers, but not billed, is estimated and corresponding unbilled revenue is

recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calculated

by estimating the megawatt hours (“MWh”) or therms delivered to customers at the established rates

expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of

energy demand, weather, line losses and inter-period changes to customer classes.

Exhibit 99.3

Non-regulated Revenue:

Marketing and trading margins are comprised of Emera Energy’s corresponding purchases and sales of

natural gas and electricity, pipeline capacity costs and energy asset management revenues. Revenues

are recorded when obligations under terms of the contract are satisfied and are presented on a net basis

reflecting the nature of contractual relationships with customers and suppliers.

Energy sales are recognized when obligations under the terms of the contracts are satisfied, which is

when electricity is delivered to customers over time.

Other non-regulated revenues are recorded when obligations under the terms of the contract are

satisfied.

Other:

Sales, value add, and other taxes, except for gross receipts taxes discussed below, collected by the

Company concurrent with revenue-producing activities are excluded from revenue.

Franchise Fees and Gross Receipts

TEC and PGS recover from customers certain costs incurred, on a dollar-for-dollar basis, through prices

approved by the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills

for franchise fees and gross receipt taxes are included as “Regulated electric” and “Regulated gas”

revenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by

TEC and PGS are included as an expense on the Consolidated Statements of Income in “Provincial, state

and municipal taxes”.

NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not

required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross

receipt taxes are presented net with no line item impact on the Consolidated Statements of Income.

PP&E

PP&E is recorded at original cost, including AFUDC or capitalized interest, net of contributions received in

aid of construction.

The cost of additions, including betterments and replacements of units, are included in “PP&E” on the

Consolidated Balance Sheets. When units of regulated PP&E are replaced, renewed or retired, their cost,

plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no

gain or loss reflected in income. Where a disposition of non-regulated PP&E occurs, gains and losses are

included in income as the dispositions occur.

The cost of PP&E represents the original cost of materials, contracted services, direct labour, AFUDC for

regulated property or interest for non-regulated property, ARO, and overhead attributable to the capital

project. Overhead includes corporate costs such as finance, information technology and labour costs,

along with other costs related to support functions, employee benefits, insurance, procurement, and fleet

operating and maintenance. Expenditures for project development are capitalized if they are expected to

have a future economic benefit.

Normal maintenance projects and major maintenance projects that do not increase overall life of the

related assets are expensed as incurred. When a major maintenance project increases the life or value of

the underlying asset, the cost is capitalized.

Depreciation is determined by the straight-line method, based on the estimated remaining service lives of

the depreciable assets in each functional class of depreciable property. For some of Emera’s rate-

regulated subsidiaries, depreciation is calculated using the group remaining life method, which is applied

to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of

depreciable property. The service lives of regulated assets require regulatory approval.

Exhibit 99.3

Intangible assets, which are included in “PP&E” on the Consolidated Balance Sheets, consist primarily of

computer software and land rights. Amortization is determined by the straight-line method, based on the

estimated remaining service lives of the asset in each category. For some of Emera’s rate-regulated

subsidiaries, amortization is calculated using the amortizable life method which is applied to the net book

value to date over the remaining life of those assets. The service lives of regulated intangible assets

require regulatory approval.

Goodwill

Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated FV of

identifiable assets acquired and liabilities assumed at the acquisition date. Goodwill is carried at initial

cost less any write-down for impairment and is adjusted for the impact of foreign exchange (“FX”).

Goodwill is subject to assessment for impairment at the reporting unit level annually, or if an event or

change in circumstances indicates that the FV of a reporting unit may be below its carrying value. When

assessing goodwill for impairment, the Company has the option of first performing a qualitative

assessment to determine whether a quantitative assessment is necessary. In performing a qualitative

assessment management considers, among other factors, macroeconomic conditions, industry and

market considerations and overall financial performance.

If the Company performs a qualitative assessment and determines it is more likely than not that its FV is

less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a

quantitative test is performed. The quantitative test compares the FV of the reporting unit to its carrying

amount, including goodwill. If the carrying amount of the reporting unit exceeds its FV, an impairment loss

is recorded. Management estimates the FV of the reporting unit by using the income approach, or a

combination of the income and market approach. The income approach uses a discounted cash flow

analysis which relies on management’s best estimate of the reporting unit’s projected cash flows. The

analysis includes an estimate of terminal values based on these expected cash flows using a

methodology which derives a valuation using an assumed perpetual annuity based on the reporting unit’s

residual cash flows. The discount rate used is a market participant rate based on a peer group of publicly

traded comparable companies and represents the weighted average cost of capital of comparable

companies. For the market approach, management estimates FV based on comparable companies and

transactions within the utility industry. Significant assumptions used in estimating the FV of a reporting

unit using an income approach include discount and growth rates, rate case assumptions including future

cost of capital, valuation of the reporting unit’s net operating loss (“NOL”) and projected operating and

capital cash flows. Adverse changes in these assumptions could result in a future material impairment of

the goodwill assigned to Emera’s reporting units.

As of December 31, 2023, $

5,868

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.

In Q4 2022, as a result of a quantitative assessment, the Company recorded a goodwill impairment

charge of $

million, reducing the GBPC goodwill balance to

nil

as at December 31, 2022. For further

details, refer to note 22.

Exhibit 99.3

Income Taxes and Investment Tax

Credits

Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events

that have been included in financial statements or income tax returns. Deferred income tax assets and

liabilities are determined based on the difference between the carrying value of assets and liabilities on

the Consolidated Balance Sheets, and their respective tax bases using enacted tax rates in effect for the

year in which the differences are expected to reverse. The effect of a change in income tax rates on

deferred income tax assets and liabilities is recognized in earnings in the period when the change is

enacted, unless required to be offset to a regulatory asset or liability by law or by order of the regulator.

Emera recognizes the effect of income tax positions only when it is more likely than not that they will be

realized. Management reviews all readily available current and historical information, including forward-

looking information, and the likelihood that deferred income tax assets will be recovered from future

taxable income is assessed and assumptions are made about the expected timing of reversal of deferred

income tax assets and liabilities. If management subsequently determines it is likely that some or all of a

deferred income tax asset will not be realized, a valuation allowance is recorded to reflect the amount of

deferred income tax asset expected to be realized.

Generally, investment tax credits are recorded as a reduction to income tax expense in the current or

future periods to the extent that realization of such benefit is more likely than not. Investment tax credits

earned on regulated assets by TEC, PGS and NMGC are deferred and amortized as required by

regulatory practices.

TEC, PGS, NMGC and BLPC collect income taxes from customers based on current and deferred income

taxes. NSPI, ENL and Brunswick Pipeline collect income taxes from customers based on income tax that

is currently payable, except for the deferred income taxes on certain regulatory balances specifically

prescribed by regulators. For the balance of regulated deferred income taxes, NSPI, ENL and Brunswick

Pipeline recognize regulatory assets or liabilities where the deferred income taxes are expected to be

recovered from or returned to customers in future years. These regulated assets or liabilities are grossed

up using the respective income tax rate to reflect the income tax associated with future revenues that are

required to fund these deferred income tax liabilities, and the income tax benefits associated with reduced

revenues resulting from the realization of deferred income tax assets. GBPC is not subject to income

taxes.

Emera classifies interest and penalties associated with unrecognized tax benefits as interest and

operating expense, respectively. For further detail, refer to note 10.

Derivatives and Hedging Activities

The Company manages its exposure to normal operating and market risks relating to commodity prices,

FX, interest rates and share prices through contractual protections with counterparties where practicable,

and by using financial instruments consisting mainly of FX forwards and swaps, interest rate options and

swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the

Company has contracts for the physical purchase and sale of natural gas. These physical and financial

contracts are classified as HFT. Collectively,

these contracts and financial instruments are considered

derivatives.

The Company recognizes the FV of all its derivatives on its balance sheet, except for non-financial

derivatives that meet the normal purchases and normal sales (“NPNS”) exception. Physical contracts that

meet the NPNS exception are not recognized on the balance sheet; these contracts are recognized in

income when they settle. A physical contract generally qualifies for the NPNS exception if the transaction

is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources

within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the

commodity, and the Company deems the counterparty creditworthy.

The Company continually assesses

contracts designated under the NPNS exception and will discontinue the treatment of these contracts

under this exemption if the criteria are no longer met.

Exhibit 99.3

Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be

proven to effectively hedge identified risk both at the inception and over the term of the instrument.

Specifically, for cash flow hedges, change in the FV of derivatives is deferred to AOCI and recognized in

income in the same period the related hedged item is realized. Where documentation or effectiveness

requirements are not met, the derivatives are recognized at FV with any changes in FV recognized in net

income in the reporting period, unless deferred as a result of regulatory accounting.

Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for

which the NPNS exception has not been taken, are subject to regulatory accounting treatment. The

change in FV of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized

in the hedged item when the hedged item is settled. Management believes any gains or losses resulting

from settlement of these derivatives related to fuel for generation and purchased power will be refunded

to or collected from customers in future rates. TEC 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.

Emera classifies gains and losses on derivatives as a component of non-regulated operating revenues,

fuel for generation and purchased power, other expenses, inventory, and OM&G, depending on the

nature of the item being economically hedged. Transportation capacity arising as a result of marketing

and trading derivative transactions is recognized as an asset in “Receivables and other current assets”

and amortized over the period of the transportation contract term. Cash flows from derivative activities are

presented in the same category as the item being hedged within operating or investing activities on the

Consolidated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on

the Consolidated Statements of Cash Flows.

Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the FV amounts of cash

collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables

and other current assets” and obligations to return cash collateral are recognized in “Accounts payable”.

Leases

The Company determines whether a contract contains a lease at inception by evaluating whether the

contract conveys the right to control the use of an identified asset for a period of time in exchange for

consideration.

Emera has leases with independent power producers (“IPP”) and other utilities for annual requirements to

purchase wind and hydro energy over varying contract lengths which are classified as finance leases.

These finance leases are not recorded on the Company’s Consolidated Balance Sheets as payments

associated with the leases are variable in nature and there are no minimum fixed lease payments. Lease

expense associated with these leases is recorded as “Regulated fuel for generation and purchased

power” on the Consolidated Statements of Income.

Operating lease liabilities and right-of-use assets are recognized on the Consolidated Balance Sheets

based on the present value of the future minimum lease payments over the lease term at commencement

date. As most of Emera’s leases do not provide an implicit rate, the incremental borrowing rate at

commencement of the lease is used in determining the present value of future lease payments. Lease

expense is recognized on a straight-line basis over the lease term and is recorded as “Operating,

maintenance and general” on the Consolidated Statements of Income.

Exhibit 99.3

Where the Company is the lessor, a lease is a sales-type lease if certain criteria are met and the

arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria

are met due to the presence of a third-party residual value guarantee, the lease is a direct financing

lease.

For direct finance leases, a net investment in the lease is recorded that consists of the sum of the

minimum lease payments and residual value, net of estimated executory costs and unearned income.

The difference between the gross investment and the cost of the leased item is recorded as unearned

income at the inception of the lease. Unearned income is recognized in income over the life of the lease

using a constant rate of interest equal to the internal rate of return on the lease.

For sales-type leases, the accounting is similar to the accounting for direct finance leases however, the

difference between the FV and the carrying value of the leased item is recorded at lease commencement

rather than deferred over the term of the lease.

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

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

Cash, Cash Equivalents and Restricted Cash

Cash equivalents consist of highly liquid short-term investments with original maturities of three months or

less at acquisition.

Receivables and Allowance for Credit Losses

Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard

payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be

assessed on account balances after the due date. The Company recognizes allowances for credit losses

to reduce accounts receivable for amounts expected to be uncollectable. Management estimates credit

losses related to accounts receivable by considering historical loss experience, customer deposits,

current events, the characteristics of existing accounts and reasonable and supportable forecasts that

affect the collectability of the reported amount. Provisions for credit losses on receivables are expensed

to maintain the allowance at a level considered adequate to cover expected losses. Receivables are

written off against the allowance when they are deemed uncollectible.

Inventory

Fuel and materials inventories are valued at the lower of weighted-average cost or net realizable value,

unless evidence indicates the weighted-average cost will be recovered in future customer rates.

Asset Impairment

Long-Lived Assets:

Emera assesses whether there has been an impairment of long-lived assets and intangibles when a

triggering event occurs, such as a significant market disruption or sale of a business.

The assessment involves comparing undiscounted expected future cash flows to the carrying value of the

asset. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the

amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-

lived asset over its estimated FV. The Company’s assumptions relating to future results of operations or

other recoverable amounts, are based on a combination of historical experience, fundamental economic

analysis, observable market activity and independent market studies. The Company’s expectations

regarding uses and holding periods of assets are based on internal long-term budgets and projections,

which consider external factors and market forces, as of the end of each reporting period. The

assumptions made are consistent with generally accepted industry approaches and assumptions used for

valuation and pricing activities.

Exhibit 99.3

As at December 31, 2023, there are no indications of impairment of Emera’s long-lived assets.

impairment charges related to long-lived assets were recognized in 2023 or 2022.

Equity Method Investments:

The carrying value of investments accounted for under the equity method are assessed for impairment by

comparing the FV of these investments to their carrying values, if a FV assessment was completed, or by

reviewing for the presence of impairment indicators. If an impairment exists, and it is determined to be

other-than-temporary, a charge is recognized in earnings equal to the amount the carrying value exceeds

the investment’s FV.

impairment of equity method investments was required in either 2023 or 2022.

Financial Assets:

Equity investments, other than those accounted for under the equity method, are measured at FV, with

changes in FV recognized in the Consolidated Statements of Income. Equity investments that do not

have readily determinable FV are recorded at cost minus impairment, if any, plus or minus changes

resulting from observable price changes in orderly transactions for the identical or similar investments.

impairment of financial assets was required in either 2023 or 2022.

Asset Retirement Obligations

An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs

resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation

may exist under an existing or enacted law or statute, written or oral contract, or by legal construction

under the doctrine of promissory estoppel.

An ARO represents the FV of estimated cash flows necessary to discharge the future obligation, using

the Company’s credit adjusted risk-free rate. The amounts are reduced by actual expenditures incurred.

Estimated future cash flows are based on completed depreciation studies, remediation reports, prior

experience, estimated useful lives, and governmental regulatory requirements. The present value of the

liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased.

The amount capitalized at inception is depreciated in the same manner as the related long-lived asset.

Over time, the liability is accreted to its estimated future value. AROs are included in “Other long-term

liabilities” and accretion expense is included as part of “Depreciation and amortization”. Any regulated

accretion expense not yet approved by the regulator is recorded in “Property, plant and equipment” and

included in the next depreciation study.

Some of the Company’s transmission and distribution assets may have conditional AROs that are not

recognized in the consolidated financial statements, as the FV of these obligations could not be

reasonably estimated, given insufficient information to do so. A conditional ARO refers to a legal

obligation to perform an asset retirement activity in which the timing and/or method of settlement are

conditional on a future event that may or may not be within the control of the entity. Management

monitors these obligations and a liability is recognized at FV in the period in which an amount can be

determined.

Cost of Removal (“COR”)

TEC, PGS, NMGC and NSPI recognize non-ARO COR as regulatory liabilities. The non-ARO COR

represent funds received from customers through depreciation rates to cover estimated future non-legally

required COR of PP&E upon retirement. The companies accrue for COR over the life of the related

assets based on depreciation studies approved by their respective regulators. The costs are estimated

based on historical experience and future expectations, including expected timing and estimated future

cash outlays.

Exhibit 99.3

Stock-Based Compensation

The Company has several stock-based compensation plans: a common share option plan for senior

management; an employee common share purchase plan; a deferred share unit (“DSU”) plan; a

performance share unit (“PSU”) plan; and a restricted share unit (“RSU”) plan. The Company accounts for

its plans in accordance with the FV-based method of accounting for stock-based compensation. Stock-

based compensation cost is measured at the grant date, based on the calculated FV of the award, and is

recognized as an expense over the employee’s or director’s requisite service period using the graded

vesting method. Stock-based compensation plans recognized as liabilities are initially measured at FV

and re-measured at FV at each reporting date, with the change in liability recognized in income.

Employee Benefits

The costs of the Company’s pension and other post-retirement benefit programs for employees are

expensed over the periods during which employees render service. The Company recognizes the funded

status of its defined-benefit and other post-retirement plans on the balance sheet and recognizes

changes in funded status in the year the change occurs. The Company recognizes unamortized gains

and losses and past service costs in “AOCI” or “Regulatory assets” on the Consolidated Balance Sheets.

The components of net periodic benefit cost other than the service cost component are included in “Other

income, net” on the Consolidated Statements of Income. For further detail, refer to note 21.

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 99.3

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.

DISPOSITIONS

On March 31, 2022, Emera completed the sale of its

51.9

per cent interest in Domlec for proceeds which

approximated its carrying value. Domlec was included in the Company’s Other Electric reportable

segment up to its date of sale. The sale did not have a material impact on earnings.

Exhibit 99.3

SEGMENT INFORMATION

Emera manages its reportable segments separately due in part to their different operating, regulatory and

geographical environments. Segments are reported based on each subsidiary’s contribution of revenues,

net income attributable to common shareholders and total assets, as reported to the Company’s chief

operating decision maker.

Florida

Canadian

Gas Utilities

Other

Inter-

Electric

and

Electric

Segment

millions of dollars

Utility

Utilities

Infrastructure

Utilities

Other

Eliminations

Total

For the year ended December 31, 2023

Operating revenues from

external customers (1)

3,548

1,671

1,510

526

308

7,563

Inter-segment revenues

(1)

(53)

Total operating revenues

3,556

1,671

1,524

526

339

(53)

7,563

Regulated fuel for generation

and purchased power

920

699

275

(13)

1,881

Regulated cost of natural gas

527

OM&G

830

384

405

130

151

(21)

1,879

Provincial, state and municipal

taxes

289

433

Depreciation and amortization

571

276

126

1,049

Income from equity

investments

109

146

Other income, net

158

Interest expense, net

(2)

271

170

129

332

925

Income tax expense

(recovery)

117

(9)

(44)

128

Non-controlling interest in

subsidiaries

Preferred stock dividends

Net income (loss) attributable

to common shareholders

627

247

214

(147)

978

Capital expenditures

1,736

450

664

2,921

As at December 31, 2023

Total assets

21,119

8,634

7,735

1,311

1,938

(1,257)

39,480

Investments subject to

significant influence

1,236

118

1,402

Goodwill

4,628

1,240

5,871

(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions

between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E,

OM&G, or regulated fuel for generation and purchased power. Inter-company

transactions that have not been eliminated are

measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are

included in

determining reportable segments.

(2) Segment net income is reported on a basis that includes internally allocated financing costs of $

million for the year ended

December 31, 2023, between the Florida Electric Utility,

Gas Utilities and Infrastructure and Other segments.

Exhibit 99.3

Florida

Canadian

Gas Utilities

Other

Inter-

Electric

and

Electric

Segment

millions of dollars

Utility

Utilities

Infrastructure

Utilities

Other

Eliminations

Total

For the year ended December 31, 2022

Operating revenues from

external customers

(1)

3,280

1,675

1,697

518

418

7,588

Inter-segment revenues

(1)

(36)

Total operating revenues

3,287

1,675

1,704

518

440

(36)

7,588

Regulated fuel for generation

and purchased power

1,086

803

290

(8)

2,171

Regulated cost of natural gas

800

OM&G

625

338

365

123

156

(11)

1,596

Provincial, state and municipal

taxes

235

367

Depreciation and amortization

507

259

118

952

Income from equity

investments

129

Other income (expenses), net

145

Interest expense, net

(2)

185

136

288

709

GBPC impairment charge

Income tax expense (recovery)

121

(8)

185

Non-controlling interest in

subsidiaries

Preferred stock dividends

Net income (loss) attributable

to common shareholders

596

215

221

(48)

(39)

945

Capital expenditures

1,425

507

574

2,575

As at December 31, 2022

Total assets

21,053

8,223

7,737

1,337

2,835

(1,443)

39,742

Investments subject to

significant influence

1,241

128

1,418

Goodwill

4,739

1,270

6,012

(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions

between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E,

OM&G, or regulated fuel for generation and purchased power. Inter-company

transactions that have not been eliminated are

measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are

included in

determining reportable segments.

(2) Segment net income is reported on a basis that includes internally allocated financing costs of $

million for the year ended

December 31, 2022, between the Gas Utilities and Infrastructure and Other segments.

Geographical Information

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

For the

Year ended December 31

millions of dollars

2023

2022

United States

5,310

5,346

Canada

1,727

1,725

Barbados

389

384

The Bahamas

137

122

Dominica

7,563

7,588

Property Plant and Equipment:

As at

December 31

millions of dollars

2023

2022

United States

18,588

17,382

Canada

4,878

4,689

Barbados

576

583

The Bahamas

334

342

24,376

22,996

Exhibit 99.3

REVENUE

The following disaggregates the Company’s revenue by major source:

Electric

Gas

Other

Florida

Canadian

Other

Gas Utilities

Inter-

Electric

and

Segment

millions of dollars

Utility

Utilities

Infrastructure

Other

Eliminations

Total

For the year ended December 31, 2023

Regulated Revenue

Residential

2,307

910

183

724

4,124

Commercial

1,083

463

285

425

2,256

Industrial

274

219

(13)

606

Other electric

395

443

Regulatory deferrals

(522)

(510)

Other (1)

199

(8)

254

Finance income (2)(3)

Regulated revenue

3,556

1,671

526

1,503

(21)

7,235

Non-Regulated Revenue

Marketing and trading margin (4)

Other non-regulated operating

revenue

(23)

Mark-to-market (3)

216

(9)

207

Non-regulated revenue

339

(32)

328

Total operating revenues

3,556

1,671

526

1,524

339

(53)

7,563

For the year ended December 31, 2022

Regulated Revenue

Residential

1,799

834

184

800

3,617

Commercial

869

427

282

461

2,039

Industrial

230

353

(7)

691

Other electric

398

432

Regulatory deferrals

(27)

(21)

Other (1)

283

(7)

335

Finance income (2)(3)

Regulated revenue

3,287

1,675

518

1,688

(14)

7,154

Non-Regulated

Marketing and trading margin (4)

143

Other non-regulated operating

revenue

(10)

Mark-to-market (3)

281

(12)

269

Non-regulated revenue

440

(22)

434

Total operating revenues

3,287

1,675

518

1,704

440

(36)

7,588

(1) Other includes rental revenues, which do not represent revenue from contracts with customers.

(2) Revenue related to Brunswick Pipeline's service agreement with Repsol Energy Canada.

(3) Revenue which does not represent revenues from contracts with customers.

(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts

with

customers.

Remaining Performance Obligations:

Remaining performance obligations primarily represent gas transportation contracts, lighting contracts,

and long-term steam supply arrangements with fixed contract terms. As of December 31, 2023, the

aggregate amount of the transaction price allocated to remaining performance obligations was $

488

million (2022 – $

450

million). This amount includes $

134

million of future performance obligations related

to a gas transportation contract between SeaCoast and PGS through

2040

. This amount excludes

contracts with an original expected length of one year or less and variable amounts for which Emera

recognizes revenue at the amount to which it has the right to invoice for services performed. Emera

expects to recognize revenue for the remaining performance obligations through

2043

Exhibit 99.3

6. REGULATORY

ASSETS AND LIABILITIES

Regulatory assets represent prudently incurred costs that have been deferred because it is probable they

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

regulatory assets are probable for recovery either because the Company received specific approval from

the applicable regulator, or due to regulatory precedent established for similar circumstances. If

management no longer considers it probable that an asset will be recovered, deferred costs are charged

to income.

Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for

previous collections. If management no longer considers it probable that a liability will be settled, the

related amount is recognized in income.

For regulatory assets and liabilities that are amortized, the amortization is as approved by the respective

regulator.

As at

December 31

millions of dollars

2023

2022

Regulatory assets

Deferred income tax regulatory assets

1,233

1,166

TEC capital cost recovery for early retired assets

671

674

NSPI FAM

395

307

Pension and post-retirement medical plan

364

369

Cost recovery clauses

151

707

Deferrals related to derivative instruments

Storm cost recovery clauses

138

Environmental remediations

Stranded cost recovery

NMGC winter event gas cost recovery

Other

100

106

3,105

3,620

Current

339

602

Long-term

2,766

3,018

Total regulatory assets

3,105

3,620

Regulatory liabilities

Accumulated reserve – COR

849

895

Deferred income tax regulatory liabilities

830

877

Cost recovery clauses

BLPC Self-insurance fund ("SIF") (note 32)

Deferrals related to derivative instruments

230

NMGC gas hedge settlements (note 18)

162

Other

1,772

2,273

Current

168

495

Long-term

1,604

1,778

Total regulatory liabilities

1,772

2,273

Deferred Income Tax Regulatory Assets and Liabilities

the extent deferred income taxes are expected to be recovered from or returned to customers in future

years, a regulatory asset or liability is recognized as appropriate.

Exhibit 99.3

TEC Capital Cost Recovery for Early Retired Assets

This regulatory asset is related to the remaining net book value of Big Bend Power Station Units 1

through 3 and smart meter assets that were retired. The balance earns a rate of return as permitted by

the FPSC and is recovered as a separate line item on customer bills for a period of

15 years

. This

recovery mechanism is authorized by and survives the term of the settlement agreement approved by the

FPSC in 2021. For further information, refer to “Big Bend Modernization Project” in the TEC section

below.

NSPI FAM

NSPI has a FAM, approved by the UARB, allowing NSPI to recover fluctuating fuel and certain fuel-

related costs from customers through regularly scheduled fuel rate adjustments. Differences between

prudently incurred fuel costs and amounts recovered from customers through electricity rates in a year

are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in

subsequent periods.

Pension and Post-Retirement Medical Plan

This asset is primarily related to the deferred costs of pension and post-retirement benefits at TEC, PGS

and NMGC. It is included in rate base and earns a rate of return as permitted by the FPSC and NMPRC,

as applicable. It is amortized over the remaining service life of plan participants.

Cost Recovery Clauses

These assets and liabilities are related to TEC, PGS and NMGC clauses and riders. They are recovered

or refunded through cost-recovery mechanisms approved by the FPSC or New Mexico Public Regulation

Commission (“NMPRC”), as applicable, on a dollar-for-dollar basis in a subsequent period.

Deferrals Related to Derivative Instruments

This asset is primarily related to NSPI deferring changes in FV of derivatives that are documented as

economic hedges or that do not qualify for NPNS exemption, as a regulatory asset or liability as approved

by the UARB. The realized gain or loss is recognized when the hedged item settles in regulated fuel for

generation and purchased power, other income, inventory,

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

being economically hedged.

Storm Cost Recovery Clauses

TEC and PGS Storm Reserve:

The storm reserve is for hurricanes and other named storms that cause significant damage to TEC and

PGS systems. As allowed by the FPSC, if charges to the storm reserve exceed the storm liability, the

excess is to be carried as a regulatory asset. TEC and PGS can petition the FPSC to seek recovery of

restoration costs over a 12-month period or longer, as determined by the FPSC, as well as replenish the

reserve. In 2022, TEC and PGS were impacted by Hurricane Ian. For further information, refer to “TEC

Storm Reserve” in the Florida Electric Utility section below.

NSPI Storm Rider:

NSPI has a UARB approved storm rider for each of 2023, 2024 and 2025, which gives NSPI the option to

apply to the UARB for recovery of costs if major storm restoration expenses exceed approximately $

million in a given year.

GBPC Storm Restoration:

This asset represents storm restoration costs incurred by GBPC. GBPC maintains insurance for its

generation facilities and, as with most utilities, its transmission and distribution networks are not covered

by commercial insurance.

Exhibit 99.3

In January 2020, the Grand Bahama Port Authority (“GBPA”) approved recovery of $

million USD of

2019 costs related to Hurricane Dorian, over a five-year period from 2021 through 2025.

Restoration costs associated with Hurricane Matthew in 2016 are being recovered through an approved

fuel charge. For further information, refer to “Storm Restoration Costs – Hurricane Matthew” in the GBPC

section below.

Environmental Remediations

This asset is primarily related to PGS costs associated with environmental remediation at Manufactured

Gas Plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a

rate of return as permitted by the FPSC. The timing of recovery is based on a settlement agreement

approved by the FPSC.

Stranded Cost Recovery

Due to decommissioning of a GBPC steam turbine in 2012, the GBPA approved recovery of a $

million

USD stranded cost through electricity rates; it is included in rate base and expected to be included in

rates in future years.

NMGC Winter Event Gas Cost Recovery

In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in

an incremental $

108

million USD for gas costs above what it would normally have paid during this period.

NMGC normally recovers gas supply and related costs through a purchased gas adjustment clause

(“PGAC”). On June 15, 2021, the NMPRC approved recovery of $

108

million USD and related borrowing

costs in customer rates over a period of

30 months

from July 1, 2021, to December 31, 2023.

Accumulated Reserve – COR

This regulatory liability represents the non-ARO COR reserve in TEC, PGS, NMGC and NSPI. AROs

represent the FV of estimated cash flows associated with the Company’s legal obligation to retire its

PP&E. Non-ARO COR represent estimated funds received from customers through depreciation rates to

cover future COR of PP&E value upon retirement that are not legally required. This reduces rate base for

ratemaking purposes. This liability is reduced as COR are incurred and increased as depreciation is

recorded for existing assets and as new assets are put into service.

NMGC Gas Hedge Settlements

This regulatory liability represents regulatory deferral of gas options exercised above strike price but

settled subsequent to the period end. The value from cash settlement of these options flows to customers

via the PGAC.

Other Regulatory Assets and Liabilities

Comprised of regulatory assets and liabilities that are not individually significant.

Exhibit 99.3

Regulatory Environments and Updates

Florida Electric Utility

TEC is regulated by the FPSC and is also subject to regulation by the Federal Energy Regulatory

Commission. The FPSC sets rates at a level that allows utilities such as TEC to collect total revenues or

revenue requirements equal to their cost of providing service, plus an appropriate return on invested

capital. Base rates are determined in FPSC rate setting hearings which can occur at the initiative of TEC,

the FPSC or other interested parties.

TEC’s approved regulated return on equity (“ROE”) range for 2023 and 2022 was

9.25

per cent to

11.25

per cent based on an allowed equity capital structure of

per cent. An ROE of

10.20

per cent (2022 –

10.20

per cent) is used for the calculation of the return on investments for clauses.

Base Rates:

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 $

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.

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

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

increase of $

million USD was approved by the FPSC on November 17, 2023.

Fuel Recovery and Other Cost Recovery Clauses:

TEC has a fuel recovery clause approved by the FPSC, allowing the opportunity to recover fluctuating

fuel expenses from customers through annual fuel rate adjustments. The FPSC annually approves cost-

recovery rates for purchased power, capacity,

environmental and conservation costs, including a return

on capital invested. Differences between prudently incurred fuel costs and the cost-recovery rates and

amounts recovered from customers through electricity rates in a year are deferred to a regulatory asset or

liability and recovered from or returned to customers in subsequent periods.

On 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.

The mid-course fuel adjustment requested by TEC on January 19, 2022, was approved on March 1,

2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel and capacity

costs of $

169

million USD, and was spread over customer bills from April 1, 2022 through December

2022.

Big Bend Modernization Project:

TEC invested $

876

million USD, including $

million USD of AFUDC, between 2018 and 2022 to

modernize the Big Bend Power Station. The modernization project repowered Big Bend Unit 1 with

natural gas combined-cycle technology and eliminated coal as this unit’s fuel. As part of the

modernization project, TEC in 2020 retired the Unit 1 components that would not be used in the

modernized plant and did the same for Big Bend Unit 2 in 2021. TEC retired Big Bend Unit 3 in 2023 as it

was in the best interests of the customers from an economic, environmental risk and operational

perspective. On December 31, 2021, the remaining costs of the retired Big Bend coal generation assets,

Units 1 through 3, of $

636

million USD and $

267

million USD in accumulated depreciation were

reclassified to a regulatory asset on the balance sheet.

Exhibit 99.3

TEC’s 2021 settlement agreement provides for cost recovery of the Big Bend Modernization project in two

phases. The first phase was a revenue increase to cover the costs of the assets in service during 2022,

among other items. The remainder of the project costs were recovered as part of the 2023 subsequent

year adjustment. The settlement agreement also includes a new charge to recover the remaining costs of

the retired Big Bend coal generation assets, Units 1 through 3, which are spread over

15 years

, effective

January 1, 2022. This recovery mechanism was authorized by and survives the term of the settlement

agreement approved by the FPSC in 2021.

Storm Reserve:

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

119

million USD of restoration costs

charged against TEC’s FPSC approved storm reserve. Total restoration costs charged to the storm

reserve exceeded the reserve balance and have been deferred as a regulatory asset for future recovery.

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

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

million

USD, for a total of $

131

million USD. The storm cost recovery surcharge was approved by the FPSC on

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

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

collection to $

134

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

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.

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

approximately $

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

minimal impact to earnings.

Storm Protection Cost Recovery Clause and Settlement Agreement:

The Storm Protection Plan (“SPP”) Cost Recovery Clause provides a process for Florida investor-owned

utilities, including TEC, to recover transmission and distribution storm hardening costs for incremental

activities not already included in base rates. Differences between prudently incurred clause-recoverable

costs and amounts recovered from customers through electricity rates in a year are deferred and

recovered from or returned to customers in a subsequent year. A settlement agreement was approved on

August 10, 2020, and TEC’s cost recovery began in January 2021. The current approved plan addressed

the years 2023, 2024 and 2025 and was approved by the FPSC on October 4, 2022.

Canadian Electric Utilities

NSPI

NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (“Public Utilities Act”) and is

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

supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are

also subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather

participates in hearings held from time to time at NSPI’s or the UARB’s request.

NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of

providing electricity service to customers and provide a reasonable return to investors. NSPI’s approved

regulated ROE range for 2023 and 2022 was

8.75

per cent to

9.25

per cent based on an actual five

quarter average regulated common equity component of up to

per cent of approved rate base.

Exhibit 99.3

General Rate Application (“GRA”):

On February 2, 2023, the UARB approved the GRA settlement agreement between NSPI, key customer

representatives and participating interest groups. This resulted in average customer rate increases of

6.9

per cent effective on February 2, 2023, and further average increases of

6.5

per cent on January 1, 2024,

with any under or over-recovery of fuel costs addressed through the UARB’s established FAM process. It

also established a storm rider and a demand-side management rider. On March 27, 2023, the UARB

issued a final order approving the electricity rates effective on February 2, 2023.

Fuel Recovery:

For the period of 2020 through 2022, NSPI operated under a three-year fuel stability plan with no fuel rate

adjustments related to the under-recovery of fuel and fuel-related costs in the period.

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

the outstanding 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

-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.

Storm Rider:

The storm rider was effective as of the GRA decision date. The application for deferral and recovery of

the storm rider is made in the year following the year of the incurred cost, with recovery beginning in the

year after the application. Total major storm restoration expense for 2023 was $

million, of which $

million was deferred to the storm rider.

Hurricane Fiona:

On October 31, 2023, NSPI submitted an application to the UARB to defer $

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 $

million is deferred to “Other long-term assets”, pending UARB

approval.

Maritime Link:

The Maritime Link is a $

1.8

billion (including AFUDC) transmission project including

two

170

-kilometre

sub-sea cables, connecting the island of Newfoundland and Nova Scotia. The Maritime Link entered

service on January 15, 2018 and NSPI started interim assessment payments to NSPML at that time.

Any difference between the amounts recovered from customers through rates and those approved by the

UARB through the NSPML interim assessment application will be addressed through the FAM.

Nova Scotia Cap-and-Trade (“Cap-and-Trade”)

Program:

As of December 31, 2022, the FAM included a cumulative $

166

million in fuel costs related to the accrued

purchase of emissions credits and $

million related to credits purchased from provincial auctions. On

March 16, 2023, the Province of Nova Scotia provided NSPI with emissions allowances sufficient to

achieve compliance for the 2019 through 2022 period. As such, compliance costs accrued of $

166

million

were reversed in Q1 2023. The credits NSPI purchased from provincial auctions in the amount of $

million were not refunded and no further costs were incurred to achieve compliance with the Cap-and-

Trade Program.

Exhibit 99.3

Extra Large Industrial Active Demand Tariff:

On July 5, 2023, NSPI received approval from the UARB to change the methodology in which fuel cost

recovery from an industrial customer is calculated. Due to significant volatility in commodity prices in

2022, the previous methodology did not result in a reasonable determination of the fuel cost to serve this

customer. The change in methodology,

effective January 1, 2022, results in a shifting of fuel costs from

this industrial customer to the FAM. This adjustment was recorded in Q2 2023 resulting in a $

million

increase to the FAM regulatory asset and an offsetting decrease to unbilled revenue within Receivables

and other current assets. This adjustment had minimal impact on earnings.

NSPML

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

performance of NSPML. NSPML’s approved regulated ROE range is

8.75

per cent to

9.25

per cent,

based on an actual five-quarter average regulated common equity component of up to

per cent.

Nalcor’s Nova Scotia Block (“NS Block”) delivery obligations commenced on August 15, 2021 and

delivery will continue over the next

35 years

pursuant to the agreements.

In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate

base of approximately $

1.8

billion less $

million of costs ($

million after-tax) that would not have

otherwise been recoverable if incurred by NSPI.

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

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

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

UARB agreed with the Company’s submission that $

million ($

million related to 2022 and $

million

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

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

per cent of the contracted annual amount. In addition, the

UARB increased the monthly holdback amount from $

million to $

million beginning December 1, 2023.

On December 21, 2023, NSPML received approval to collect up to $

164

million (2023 – $

164

million)

from NSPI for the recovery of costs associated with the Maritime Link in 2024; subject to a holdback of up

to $

million a month, as discussed above.

Gas Utilities and Infrastructure

PGS

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

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

on invested capital.

PGS’s approved ROE range for 2023 and 2022 was

8.9

per cent to

11.0

per cent with a

9.9

per cent

midpoint, based on an allowed equity capital structure of

54.7

per cent.

Base Rates:

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

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

118

million USD increase to base

revenues which includes $

million USD transferred from the cast iron and bare steel replacement rider,

for a net incremental increase to base revenues of $

107

million USD. This reflects a

10.15

per cent

midpoint ROE with an allowed equity capital structure of

54.7

per cent.  A final order was issued on

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

Exhibit 99.3

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

million USD of

accumulated depreciation through 2023. PGS reversed $

million USD of accumulated depreciation in

2023 and $

million USD in 2022.

Fuel Recovery:

PGS recovers the costs it pays for gas supply and interstate transportation for system supply through its

PGAC. This clause is designed to recover actual costs incurred by PGS for purchased gas, gas storage

services, interstate pipeline capacity, and other related items associated with the purchase, distribution,

and sale of natural gas to its customers. These charges may be adjusted monthly based on a cap

approved annually by the FPSC.

Recovery of Energy Conservation and Pipeline Replacement Programs:

The FPSC annually approves a conservation charge that is intended to permit PGS to recover prudently

incurred expenditures in developing and implementing cost effective energy conservation programs which

are required by Florida law and approved and monitored by the FPSC. PGS also has a Cast Iron/Bare

Steel Pipe Replacement clause to recover the cost of accelerating the replacement of cast iron and bare

steel distribution lines in the PGS system. In February 2017, the FPSC approved expansion of the Cast

Iron/Bare Steel clause to allow recovery of accelerated replacement of certain obsolete plastic pipe. The

majority of cast iron and bare steel pipe has been removed from its system, with replacement of obsolete

plastic pipe continuing until 2028 under the rider.

NMGC

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

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

NMGC’s approved ROE for 2023 and 2022 was

9.375

per cent on an allowed equity capital structure of

per cent.

Base Rates:

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

Q4 2024. NMGC requested $

million USD 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.

Fuel Recovery:

NMGC recovers gas supply costs through a PGAC. This clause recovers actual costs for purchased gas,

gas storage services, interstate pipeline capacity, and other related items associated with the purchase,

transmission, distribution, and sale of natural gas to its customers. On a monthly basis, NMGC can adjust

charges based on the next month’s expected cost of gas and any prior month under-recovery or over-

recovery. The NMPRC requires that NMGC annually file a reconciliation of the PGAC period costs and

recoveries. NMGC must file a PGAC Continuation Filing with the NMPRC every four years to establish

that the continued use of the PGAC is reasonable and necessary. NMGC received approval of its PGAC

Continuation in December 2020, for the four-year period ending December 2024.

Integrity Management Programs (“IMP”) Regulatory Asset:

A portion of NMGC’s annual spending on infrastructure is for IMP,

or the replacement and update of

legacy systems. These programs are driven both by NMGC integrity management plans and federal and

state mandates. In December 2020, NMGC received approval through its rate case to defer costs through

an IMP regulatory asset for certain of its IMP capital investments occurring between January 1, 2022 and

December 31, 2023 and petitioned recovery of the regulatory asset in its rate case filed on December 13,

2021. On November 30, 2022, the NMPRC issued a Final Order that included approval of recovery of the

IMP regulatory asset.

Exhibit 99.3

Brunswick Pipeline

Brunswick Pipeline is a

145

-kilometre pipeline delivering natural gas from the Saint John LNG import

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

Pipeline entered into a

-year firm service agreement commencing in July 2009 with Repsol Energy

North America Canada Partnership. The agreement provides for a predetermined toll increase in the fifth

and fifteenth year of the contract. The pipeline is considered a Group II pipeline regulated by the Canada

Energy Regulator (“CER”). The CER Gas Transportation Tariff

is filed by Brunswick Pipeline in

compliance with the requirements of the CER Act and sets forth the terms and conditions of the

transportation rendered by Brunswick Pipeline.

Other Electric Utilities

BLPC

BLPC is regulated by the Fair Trading Commission (“FTC”), under the Utilities Regulation (Procedural)

Rules 2003. BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred

costs of providing electricity service to customers plus an appropriate return on capital invested. BLPC’s

approved regulated return on rate base was

per cent for 2023 and 2022.

Licenses:

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

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

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

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

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

implementation of the licenses once enacted.

Base Rates:

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

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

million USD per

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

application which included the following

significant items: an allowed regulatory ROE of

11.75

per cent, an equity capital structure of

per cent,

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

establish regulatory liabilities related to the self-insurance fund of $

million USD, prior year benefits

recognized on remeasurement of deferred income taxes of $

million USD, and accumulated depreciation

of $

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.

Fuel Recovery:

BLPC’s fuel costs flow through a fuel pass-through mechanism which provides opportunity to recover all

prudently incurred fuel costs from customers in a timely manner. The calculation of the fuel charge is

adjusted on a monthly basis and reported to the FTC for approval.

Exhibit 99.3

Clean Energy Transition Program (“CETP”):

On May 31, 2023, the FTC approved BLPC’s application to establish an alternative cost recovery

mechanism to recover prudently incurred costs associated with its CETP (the “Decision”). The

mechanism is intended to facilitate the timely recovery between rate cases of costs associated with

approved renewable energy assets. BLPC will be required to submit an individual application for the

recovery of costs of each asset through the cost recovery mechanism, meeting the minimum criteria as

set out in the Decision. On October 5, 2023, BLPC applied to the FTC to recover the costs of a battery

storage system through the CETP.

Fuel Hedging:

On October 21, 2021, the FTC approved BLPC’s application to implement a fuel hedging program which

will be incorporated into the calculation of the fuel clause adjustment. On November 10, 2021, BLPC

requested the FTC review the required

/50 cost sharing arrangement between BLPC and customers in

relation to the hedging administrative costs, or any gains and losses associated with the hedging

program.

GBPC

GBPC is regulated by the GBPA. The GBPA

has granted GBPC a licensed, regulated and exclusive

franchise to produce, transmit and distribute electricity on the island until 2054. Rates are set to recover

prudently incurred costs of providing electricity service to customers plus an appropriate return on rate

base. GBPC’s approved regulated return on rate base was

8.32

per cent for 2023 (2022 –

8.23

per cent).

Base Rates:

There is a fuel pass-through mechanism and tariff review policy with new rates submitted every three

years. On January 14, 2022, the GBPA issued its decision on GBPC’s application for rate review that was

filed with the GBPA on September 23, 2021. The decision, which became effective April 1, 2022, allows

for an increase in revenues of $

3.5

million USD. The rates include a regulatory ROE of

12.84

per cent.

Fuel Recovery:

GBPC’s fuel costs flow through a fuel pass-through mechanism which provides the opportunity to recover

all prudently incurred fuel costs from customers in a timely manner.

Effective November 1, 2022, GBPC’s fuel pass through charge was increased due to an increase in

global oil prices impacting the unhedged fuel cost. In 2023, the fuel pass through charge was adjusted

monthly, in-line with actual fuel costs.

Storm Restoration Costs – Hurricane Matthew:

As part of the recovery of costs incurred as a result of Hurricane Matthew, in 2016, the GBPA approved a

fixed per kWh fuel charge and allowed the difference between this and the actual cost of fuel to be

applied to the Hurricane Matthew regulatory asset. As part of its decision on GBPC’s application for rate

review, issued January 14, 2022, and effective April 1, 2022, the GBPA

approved the continued

amortization of the remaining regulatory asset over the three year period ending December 31, 2024.

Exhibit 99.3

INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME

Equity Income

Percentage

Carrying Value

For the year ended

As at December 31

December 31

Ownership

millions of dollars

2023

2022

2023

2022

2023

LIL

(1)

747

740

31.0

NSPML

489

501

100.0

M&NP

(2)

118

128

12.9

Lucelec

(2)

19.5

Bear Swamp

(3)

50.0

1,402

1,418

146

129

(1) Emera indirectly owns

100

per cent of the Class B units, which comprises

24.5

per cent of the total units issued. Percentage

ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy

complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon

final costing of

all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission

Assets and Maritime

Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal

per cent of the cost of all of these

transmission developments.

(2) Emera has significant influence over the operating and financial decisions of these companies through Board representation

and

therefore, records its investment in these entities using the equity method.

(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $

179

million distribution received in 2015.

Bear Swamp's credit investment balance of $

million (2022 – $

million) is recorded in Other long-term liabilities on the

Consolidated Balance Sheets.

Equity investments include a $

million difference between the cost and the underlying FV of the

investees' assets as at the date of acquisition. The excess is attributable to goodwill.

Emera accounts for its variable interest investment in NSPML as an equity investment (note 32).

NSPML's consolidated summarized balance sheets are illustrated as follows:

As at

December 31

millions of dollars

2023

2022

Balance Sheets

Current assets

PP&E

1,473

1,517

Regulatory assets

272

265

Non-current assets

Total assets

1,795

1,828

Current liabilities

Long-term debt

(1)

1,109

1,149

Non-current liabilities

149

130

Equity

489

501

Total liabilities and equity

1,795

1,828

(1) The project debt has been guaranteed by the Government of Canada.

OTHER INCOME, NET

For the

Year ended December 31

millions of dollars

2023

2022

Interest income

AFUDC

Pension non-current service cost recovery

FX gains (losses)

(26)

TECO Guatemala Holdings award

(1)

Other

158

145

(1) On December 15, 2022, a payment of $

million 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 in TGH, a wholly-owned subsidiary of TECO Energy.

Exhibit 99.3

INTEREST EXPENSE, NET

Interest expense, net consisted of the following:

For the

Year ended December 31

millions of Canadian dollars

2023

2022

Interest on debt

954

727

Allowance for borrowed funds used during construction

(16)

(21)

Other

(13)

925

709

10.

INCOME TAXES

The income tax provision, for the years ended December 31, differs from that computed using the

enacted combined Canadian federal and provincial statutory income tax rate for the following reasons:

millions of dollars

2023

2022

Income before provision for income taxes

1,173

1,194

Statutory income tax rate

29.0%

Income taxes, at statutory income tax rate

340

346

Deferred income taxes on regulated income recorded as regulatory assets and

regulatory liabilities

(72)

(70)

Tax credits

(53)

(18)

Foreign tax rate variance

(36)

(44)

Amortization of deferred income tax regulatory liabilities

(33)

Tax effect

of equity earnings

(15)

(10)

GBPC impairment charge

Other

(3)

(7)

Income tax expense

128

185

Effective income tax rate

11%

15%

On August 16, 2022, the United States Inflation Reduction Act (“IRA”) was signed into legislation. The

IRA includes numerous tax incentives for clean energy, such as the extension and modification of existing

investment and production tax credits for projects placed in service through 2024 and introduces new

technology-neutral clean energy related tax credits beginning in 2025. As of December 31, 2023, the

Company has recorded a $

million (2022 - $

million) regulatory liability on the Consolidated Balance

Sheets in recognition of its obligation to pass the incremental tax benefits realized to customers.

The following table reflects the composition of taxes on income from continuing operations presented in

the Consolidated Statements of Income for the years ended December 31:

millions of dollars

2023

2022

Current income taxes

Canada

United States

Deferred income taxes

Canada

122

United States

128

252

Investment tax credits

United States

(29)

(7)

Operating loss carryforwards

Canada

(93)

(94)

United States

(2)

(121)

Income tax expense

128

185

Exhibit 99.3

The following table reflects the composition of income before provision for income taxes presented in the

Consolidated Statements of Income for the years ended December 31:

millions of dollars

2023

2022

Canada

171

173

United States

964

1,063

Other

(42)

Income before provision for income taxes

1,173

1,194

The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at

December 31 consisted of the following:

millions of dollars

2023

2022

Deferred income tax assets:

Tax loss carryforwards

1,195

1,207

Tax credit carryforwards

454

415

Derivative instruments

205

Regulatory liabilities

175

264

Other

372

341

Total deferred income tax assets before valuation allowance

2,401

2,272

Valuation allowance

(363)

(312)

Total deferred income tax assets after valuation allowance

2,038

1,960

Deferred income tax (liabilities):

PP&E

(3,223)

(2,981)

Derivative instruments

(235)

(125)

Investments subject to significant influence

(216)

(181)

Regulatory assets

(196)

(310)

Other

(312)

(322)

Total deferred income tax liabilities

(4,182)

(3,919)

Consolidated Balance Sheets presentation:

Long-term deferred income tax assets

208

237

Long-term deferred income tax liabilities

(2,352)

(2,196)

Net deferred income tax liabilities

(2,144)

(1,959)

Considering all evidence regarding the utilization of the Company’s deferred income tax assets, it has

been determined that Emera is more likely than not to realize all recorded deferred income tax assets,

except for certain loss carryforwards and unrealized capital losses on long-term debt and investments. A

valuation allowance of $

363

million has been recorded as at December 31, 2023 (2022 – $

312

million)

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

The Company intends to indefinitely reinvest earnings from certain foreign operations. Accordingly, as at

December 31, 2023, $

4.7

billion (2022 – $

3.8

billion) in cumulative temporary differences for which

deferred taxes might otherwise be required, have not been recognized. It is impractical to estimate the

amount of income and withholding tax that might be payable if a reversal of temporary differences

occurred.

Exhibit 99.3

Emera’s NOL, capital loss and tax credit carryforwards and their expiration periods as at December 31,

2023 consisted of the following:

Subject to

Tax

Valuation

Net Tax

Expiration

millions of dollars

Carryforwards

Allowance

Carryforwards

Period

Canada

NOL

2,914

(1,164)

1,750

2026 - 2043

Capital loss

(73)

Indefinite

United States

Federal NOL

1,360

(1)

1,359

2036 - Indefinite

State NOL

1,003

(1)

1,002

2026 - Indefinite

Tax credit

454

(3)

451

2025 - 2043

Other

NOL

(28)

2024 - 2030

The following table provides details of the change in unrecognized tax benefits for the years ended

December 31 as follows:

millions of dollars

2023

2022

Balance, January 1

Increases due to tax positions related to current year

Increases due to tax positions related to a prior year

Decreases due to tax positions related to a prior year

(2)

Balance, December 31

Unrecognized tax benefits relate to the timing of certain tax deductions at NSPI and research and

development tax credits primarily at TEC. The total amount of unrecognized tax benefits as at December

31, 2023 was $

million (2022 – $

million), which would affect the effective tax rate if recognized. The

total amount of accrued interest with respect to unrecognized tax benefits was $

million (2022 – $

million) with $

million interest expense recognized in the Consolidated Statements of Income (2022 – $

million).

penalties have been accrued. The balance of unrecognized tax benefits could change in the

next 12 months as a result of resolving Canada Revenue Agency (“CRA”) and Internal Revenue Service

audits. A reasonable estimate of any change cannot be made at this time.

During 2022, the CRA issued notices of reassessment to NSPI for the 2013 through 2016 taxation years.

NSPI and the CRA are currently in a dispute with respect to the timing of certain tax deductions for

its 2006 through 2010 and 2013 through 2016 taxation years. The ultimate permissibility of the tax

deductions is not in dispute; rather, it is the timing of those deductions. The cumulative net amount in

dispute to date is $

126

million (2022 – $

126

million), including interest. NSPI has prepaid $

million of

the amount in dispute, as required by CRA.

On November 29, 2019, NSPI filed a Notice of Appeal with the Tax Court of Canada with respect to its

dispute of the 2006 through 2010 taxation years. Should NSPI be successful in defending its position, all

payments including applicable interest will be refunded. If NSPI is unsuccessful in defending any portion

of its position, the resulting taxes and applicable interest will be deducted from amounts previously paid,

with the difference, if any, either owed to, or refunded from, the CRA. The related tax deductions will be

available in subsequent years.

Should NSPI be similarly reassessed by the CRA for years not currently in dispute, further payments will

be required; however, the ultimate permissibility of these deductions would be similarly not in dispute.

NSPI and its advisors believe that NSPI has reported its tax position appropriately. NSPI continues to

assess its options to resolving the dispute; however, the outcome of the Notice of Appeal process is not

determinable at this time.

Exhibit 99.3

Emera files a Canadian federal income tax return, which includes its Nova Scotia provincial income tax.

Emera’s subsidiaries file Canadian, US, Barbados, and St. Lucia income tax returns. As at December 31,

2023, the Company’s tax years still open to examination by taxing authorities include 2005 and

subsequent years.

11.

COMMON STOCK

Authorized

Unlimited number of non-par value common shares.

2023

2022

Issued and outstanding:

millions

of shares

millions of

dollars

millions of

dollars

Balance, January 1

269.95

7,762

261.07

7,242

Issuance of common stock under ATM program

(1)(2)

8.29

397

4.07

248

Issued under the DRIP,

net of discounts

5.26

272

4.21

238

Senior management stock options exercised and Employee Share

Purchase Plan

0.62

0.60

Balance, December 31

284.12

8,462

269.95

7,762

(1) For the year ended December 31, 2022, a total of

4,072,469

common shares were issued under Emera's ATM program

at an

average price of $

61.31

per share for gross proceeds of $

250

million ($

248

million net of after-tax issuance costs).

(2) For the year ended December 31, 2023, a total of

8,287,037

common shares were issued under Emera's ATM program

at an

average price of $

48.27

per share for gross proceeds of $

400

million ($

397

million net of after-tax issuance costs).

As at December 31, 2023, the following common shares were reserved for issuance:

million (2022 –

million) under the senior management stock option plan,

million (2022 –

2.7

million) under the employee

common share purchase plan and

million (2022 –

million) under the DRIP.

The issuance of common shares under the common share compensation arrangements does not allow

the plans to exceed

per cent of Emera's outstanding common shares. As at December 31, 2023,

Emera was in compliance with this requirement.

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.

12.

EARNINGS PER SHARE

Basic earnings per share is determined by dividing net income attributable to common shareholders by

the weighted average number of common shares outstanding during the period. Diluted EPS is computed

by dividing net income attributable to common shareholders by the weighted average number of common

shares outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive

securities. Such dilutive items include Company contributions to the senior management stock option

plan, convertible debentures and shares issued under the DRIP.

Exhibit 99.3

The following table reconciles the computation of basic and diluted earnings per share:

For the

Year ended December 31

millions of dollars (except per share amounts)

2023

2022

Numerator

Net income attributable to common shareholders

977.7

945.1

Diluted numerator

977.7

945.1

Denominator

Weighted average shares of common stock outstanding – basic

273.6

265.5

Stock-based compensation

0.2

0.4

Weighted average shares of common stock outstanding – diluted

273.8

265.9

Earnings per common share

Basic

3.57

3.56

Diluted

3.57

3.55

13.

ACCUMULATED OTHER COMPREHENSIVE INCOME

The components of AOCI are as follows:

millions of dollars

Unrealized

(loss) gain on

translation of

self-sustaining

foreign

operations

Net change in

net investment

hedges

Losses on

derivatives

recognized

as cash flow

hedges

Net change

on available-

for-sale

investments

Net change in

unrecognized

pension and

post-retirement

benefit costs

Total

AOCI

For the year ended December 31, 2023

Balance, January 1, 2023

639

(62)

(2)

(13)

578

Other comprehensive (loss)

income before

reclassifications

(270)

(232)

Amounts reclassified from

AOCI

(2)

(39)

(41)

Net current period other

comprehensive (loss) income

(270)

(2)

(39)

(273)

Balance, December 31, 2023

369

(24)

(2)

(52)

305

For the year ended December 31, 2022

Balance, January 1, 2022

(1)

(37)

Other comprehensive

income (loss) before

reclassifications

629

(97)

(1)

531

Amounts reclassified from

AOCI

(2)

Net current period other

comprehensive income (loss)

629

(97)

(2)

(1)

553

Balance, December 31, 2022

639

(62)

(2)

(13)

578

Exhibit 99.3

The reclassifications out of AOCI are as follows:

For the

Year ended December 31

millions of dollars

2023

2022

Affected line item in the Consolidated Financial Statements

Gains on derivatives recognized as cash flow hedges

Interest rate hedge

Interest expense, net

(2)

Net change in unrecognized pension and post-retirement benefit costs

Actuarial losses

Other income, net

Past service costs

Other income, net

Amounts reclassified into obligations

Pension and post-retirement benefits

(40)

Total before tax

(38)

Income tax expense

(1)

Total net of tax

(39)

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

(41)

14.

INVENTORY

As at

December 31

millions of dollars

2023

2022

Fuel

382

404

Materials

408

365

Total

790

769

15.

DERIVATIVE

INSTRUMENTS

Derivative assets and liabilities relating to the foregoing categories consisted of the following:

Derivative Assets

Derivative Liabilities

As at

December 31

millions of dollars

2023

2022

2023

2022

Regulatory deferral:

Commodity swaps and forwards

186

FX forwards

Physical natural gas purchases and sales

256

HFT derivatives:

Power swaps and physical contracts

Natural gas swaps, futures, forwards, physical

contracts

319

340

531

1,224

348

429

567

1,301

Other derivatives:

Equity derivatives

FX forwards

Total gross current derivatives

389

690

653

1,372

Impact of master netting agreements:

Regulatory deferral

(3)

(18)

(3)

(18)

HFT derivatives

(146)

(276)

(146)

(276)

Total impact of master netting agreements

(149)

(294)

(149)

(294)

Total derivatives

240

396

504

1,078

Current

(1)

174

296

386

888

Long-term

(1)

100

118

190

Total derivatives

240

396

504

1,078

(1) Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying

contracts.

Exhibit 99.3

Cash Flow Hedges

On May 26, 2021, a treasury lock was settled for a gain of $

million that is being amortized through

interest expense over

10 years

as the underlying hedged item settles.

The amounts related to cash flow hedges recorded in AOCI consisted of the following:

For the

Year ended December 31

millions of dollars

2023

2022

Interest

rate hedge

Realized gain in interest expense, net

Total gains in net income

As at

December 31

millions of dollars

2023

2022

Interest

rate hedge

Total unrealized gain in AOCI – effective portion, net of tax

The Company expects $

million of unrealized gains currently in AOCI to be reclassified into net income

within the next 12 months.

Regulatory Deferral

The Company has recorded the following changes with respect to derivatives receiving regulatory

deferral:

Physical

Commodity

Physical

Commodity

natural gas

swaps and

natural gas

swaps and

millions of dollars

purchases

forwards

purchases

forwards

For the year ended December 31

2023

2022

Unrealized gain (loss) in regulatory

assets

(109)

(3)

(69)

Unrealized gain (loss) in regulatory

liabilities

(3)

(73)

343

Realized (gain) loss in regulatory

assets

(5)

Realized (gain) loss in regulatory

liabilities

(41)

Realized (gain) loss in inventory

(1)

(10)

(121)

Realized (gain) in regulated fuel for

generation and purchased power

(2)

(49)

(9)

(4)

(64)

(146)

Other

(14)

Total change in derivative instruments

(52)

(204)

(17)

(36)

(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.

(2) Realized (gains) losses on derivative instruments settled and consumed in the period and hedging relationships that have been

terminated or the hedged transaction is no longer probable.

Exhibit 99.3

As at December 31, 2023, the Company had the following notional volumes designated for regulatory

deferral that are expected to settle as outlined below:

millions

2024

2025-2026

Physical natural gas purchases:

Natural gas (MMBtu)

Commodity swaps and forwards purchases:

Natural gas (MMBtu)

Power (MWh)

Coal (metric tonnes)

FX swaps and forwards:

FX contracts (millions of USD)

241

Weighted average rate

1.3155

1.3197

% of USD requirements

63%

17%

HFT Derivatives

The Company has recognized the following realized and unrealized gains (losses) with respect to HFT

derivatives:

For the

Year ended December 31

millions of dollars

2023

2022

Power swaps and physical contracts in non-regulated operating revenues

(6)

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

operating revenues

1,043

Total gains in net income

1,037

As at December 31, 2023, the Company had the following notional volumes of outstanding HFT

derivatives that are expected to settle as outlined below:

2028 and

millions

2024

2025

2026

2027

thereafter

Natural gas purchases (Mmbtu)

296

Natural gas sales (Mmbtu)

338

Power purchases (MWh)

Power sales (MWh)

Other Derivatives

As at December 31, 2023, the Company had equity derivatives in place to manage the cash flow risk

associated with forecasted future cash settlements of deferred compensation obligations and FX forwards

in place to manage cash flow risk associated with forecasted USD cash inflows.

The equity derivatives

hedge the return on

2.9

million shares and extends until December 2024. The FX forwards have a

combined notional amount of $508 million USD and expire in 2023, 2024 and 2025.

For the

Year ended December 31

millions of dollars

2023

2022

Equity

Forwards

Derivatives

Forwards

Derivatives

Unrealized gain (loss) in OM&G

(5)

Unrealized gain (loss) in other income, net

(18)

Realized loss in OM&G

(13)

(17)

Realized loss in other income, net

(11)

(6)

Total gains (losses) in net income

(9)

(24)

(22)

Exhibit 99.3

Credit Risk

The Company is exposed to credit risk with respect to amounts receivable from customers, energy

marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty’s

non-performance under an agreement. The Company manages credit risk with policies and procedures

for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit

assessments are conducted on all new customers and counterparties, and deposits or collateral are

requested on any high-risk accounts.

The Company assesses the potential for credit losses on a regular basis and, where appropriate,

maintains provisions. With respect to counterparties, the Company has implemented procedures to

monitor the creditworthiness and credit exposure of counterparties and to consider default probability in

valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those

that are experiencing financial problems, have significant swings in default probability rates, have credit

rating changes by external rating agencies, or have changes in ownership. Net liability positions are

adjusted based on the Company’s current default probability. Net asset positions are adjusted based on

the counterparty’s current default probability. The Company assesses credit risk internally for

counterparties that are not rated.

As at December 31, 2023, the maximum exposure the Company had to credit risk was $

1.2

billion (2022

– $

1.9

billion), which included accounts receivable net of collateral/deposits and assets related to

derivatives.

It is possible that volatility in commodity prices could cause the Company to have material credit risk

exposures with one or more counterparties. If such counterparties fail to perform their obligations under

one or more agreements, the Company could suffer a material financial loss. The Company transacts with

counterparties as part of its risk management strategy for managing commodity price, FX and interest

rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit

to the Company for the value in excess of the credit limit where contractually required. The total cash

deposits/collateral on hand as at December 31, 2023 was $

310

million (2022 – $

386

million), which

mitigated the Company’s maximum credit risk exposure. The Company uses the cash as payment for the

amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer

required by the Company.

The Company enters into commodity master arrangements with its counterparties to manage certain

risks, including credit risk to these counterparties. The Company generally enters into International Swaps

and Derivatives Association agreements, North American Energy Standards Board agreements and, or

Edison Electric Institute agreements. The Company believes entering into such agreements offers

protection by creating contractual rights relating to creditworthiness, collateral, non-performance and

default.

As at December 31, 2023, the Company had $

142

million (2022 – $

131

million) in financial assets,

considered to be past due, which have been outstanding for an average

days. The FV of these

financial assets was $

127

million (2022 – $

114

million), the difference of which was included in the

allowance for credit losses. These assets primarily relate to accounts receivable from electric and gas

revenue.

Exhibit 99.3

Concentration Risk

The Company's concentrations of risk consisted of the following:

As at

December 31, 2023

December 31, 2022

millions of

dollars

% of total

exposure

millions of

dollars

% of total

exposure

Receivables, net

Regulated utilities:

Residential

476

31%

455

19%

Commercial

194

13%

192

Industrial

121

Other

103

122

Cash collateral

951

62%

890

37%

Trading group:

Credit rating of A- or above

125

Credit rating of BBB- to BBB+

Not rated

108

307

13%

188

12%

507

21%

Other accounts receivable

151

10%

585

25%

1,290

84%

1,982

83%

Derivative Instruments

(current and long-term)

Credit rating of A- or above

138

202

Credit rating of BBB- to BBB+

Not rated

186

240

16%

396

17%

1,530

100%

2,378

100%

Cash Collateral

The Company’s cash collateral positions consisted of the following:

As at

December 31

millions of dollars

2023

2022

Cash collateral provided to others

101

224

Cash collateral received from others

112

Collateral is posted in the normal course of business based on the Company’s creditworthiness, including

its senior unsecured credit rating as determined by certain major credit rating agencies. Certain

derivatives contain financial assurance provisions that require collateral to be posted if a material adverse

credit-related event occurs. If a material adverse event resulted in the senior unsecured debt falling below

investment grade, the counterparties to such derivatives could request ongoing full collateralization.

As at December 31, 2023, the total FV of derivatives in a liability position was $

504

million (December 31,

2022

–

1,078

million). If the credit ratings of the Company were reduced below investment grade, the full

value of the net liability position could be required to be posted as collateral for these derivatives.

Exhibit 99.3

16.

FV MEASUREMENTS

The Company is required to determine the FV of all derivatives except those which qualify for the NPNS

exemption (see note 1) and uses a market approach to do so. The three levels of the FV hierarchy are

defined as follows:

Level 1 - Where possible, the Company bases the fair valuation of its financial assets and liabilities on

quoted prices in active markets (“quoted prices”) for identical assets and liabilities.

Level 2 - Where quoted prices for identical assets and liabilities are not available, the valuation of certain

contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to

location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing

houses.

Level 3 - Where the information required for a Level 1 or Level 2 valuation is not available, derivatives

must be valued using unobservable or internally-developed inputs. The primary reasons for a Level 3

classification are as follows:

●

While valuations were based on quoted prices, significant assumptions were necessary to reflect

seasonal or monthly shaping and locational basis differentials.

●

The term of certain transactions extends beyond the period when quoted prices are available and,

accordingly, assumptions were made to extrapolate prices from the last quoted period through the

end of the transaction term.

●

The valuations of certain transactions were based on internal models, although quoted prices were

utilized in the valuations.

Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is

significant to the FV measurement.

Exhibit 99.3

The following tables set out the classification of the methodology used by the Company to FV its

derivatives:

As at

December 31, 2023

millions of dollars

Level 1

Level 2

Level 3

Total

Assets

Regulatory deferral:

Commodity swaps and forwards

FX forwards

HFT derivatives:

Power swaps and physical contracts

(5)

Natural gas swaps, futures, forwards, physical

contracts and related transportation

108

184

131

202

Other derivatives:

FX forwards

Equity derivatives

Total assets

158

240

Liabilities

Regulatory deferral:

Commodity swaps and forwards

FX forwards

HFT derivatives:

Power swaps and physical contracts

Natural gas swaps, futures, forwards and physical

contracts

365

397

365

421

Other derivatives:

FX forwards

Total liabilities

365

504

Net assets (liabilities)

(8)

(331)

(264)

Exhibit 99.3

As at

December 31, 2022

millions of dollars

Level 1

Level 2

Level 3

Total

Assets

Regulatory deferral:

Commodity swaps and forwards

120

168

FX forwards

Physical natural gas purchases and sales

120

238

HFT derivatives:

Power swaps and physical contracts

Natural gas swaps, futures, forwards, physical

contracts and related transportation

109

103

153

Other derivatives:

FX forwards

Total assets

132

174

396

Liabilities

Regulatory deferral:

Commodity swaps and forwards

FX forwards

HFT derivatives:

Power swaps and physical contracts

Natural gas swaps, futures, forwards and physical

contracts

118

825

994

146

826

1,025

Other derivatives:

FX forwards

Equity derivatives

Total liabilities

179

826

1,078

Net assets (liabilities)

(5)

(736)

(682)

The change in the FV of the Level 3 financial assets for the year ended December 31, 2023 was as

follows:

Regulatory Deferral

HFT Derivatives

Physical natural

Natural

millions of dollars

gas purchases

Power

gas

Total

Balance, January 1, 2023

Realized gains (losses) included in fuel for generation

and purchased power

(49)

Unrealized gains (losses) included in regulatory

assets and liabilities

(3)

Total realized and unrealized gains (losses) included

in non-regulated operating revenues

(4)

Balance, December 31, 2023

The change in the FV of the Level 3 financial liabilities for the year ended December 31, 2023 was as

follows:

HFT Derivatives

Natural

millions of dollars

Power

gas

Total

Balance, January 1, 2023

825

826

Total realized and unrealized gains included in non-

regulated operating revenues

(1)

(460)

(461)

Balance, December 31, 2023

365

Exhibit 99.3

Significant unobservable inputs used in the FV measurement of Emera’s natural gas and power

derivatives include third-party sourced pricing for instruments based on illiquid markets. Significant

increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) FV

measurement. Other unobservable inputs used include internally developed correlation factors and basis

differentials; own credit risk; and discount rates. Internally developed correlations and basis differentials

are reviewed on a quarterly basis based on statistical analysis of the spot markets in the various illiquid

term markets. Discount rates may include a risk premium for those long-term forward contracts with

illiquid future price points to incorporate the inherent uncertainty of these points. Any risk premiums for

long-term contracts are evaluated by observing similar industry practices and in discussion with industry

peers.

The Company uses a modelled pricing valuation technique for determining the FV of Level 3 derivative

instruments. The following table outlines quantitative information about the significant unobservable

inputs used in the FV measurements categorized within Level 3 of the FV hierarchy:

Significant

Weighted

millions of dollars

Unobservable Input

Low

High

average

(1)

Assets

Liabilities

As at December 31, 2023

HFT derivatives – Natural

365

Third-party pricing

$1.27

$16.25

$4.85

gas swaps, futures, forwards

and physical contracts

Total

365

Net liability

331

As at December 31, 2022

Regulatory deferral –

Physical

Third-party pricing

$5.79

$31.85

$12.27

natural gas purchases

HFT derivatives – Power

Third-party pricing

$43.24

$269.10

$138.79

swaps and physical contracts

HFT derivatives – Natural

825

Third-party pricing

$2.45

$33.88

$12.01

gas swaps, futures, forwards

and physical contracts

Total

826

Net liability

736

(1) Unobservable inputs were weighted by the relative FV of the instruments.

Long-term debt is a financial liability not measured at FV on the Consolidated Balance Sheets. The

balance consisted of the following:

As at

Carrying

millions of dollars

Amount

Level 1

Level 2

Level 3

Total

December 31, 2023

18,365

16,621

16,363

258

16,621

December 31, 2022

16,318

14,670

14,284

386

14,670

The Company has designated $

1.2

billion USD denominated Hybrid Notes as a hedge of the foreign

currency exposure of its ne

t investment

in USD denominated operations. The Company’s Hybrid Notes

are contingently convertible into preferred shares in the event of bankruptcy or other related events. A

redemption option on or after June 15, 2026 is available and at the control of the Company. The Hybrid

Notes are classified as Level 2 financial assets. As at December 31, 2023, the FV of the Hybrid Notes

was $

1.2

billion (2022 – $

1.1

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

million was recorded in

AOCI for the year ended December 31, 2023 (2022 – $

million after-tax loss).

Exhibit 99.3

17.

RELATED PARTY

TRANSACTIONS

In the ordinary course of business, Emera provides energy and other services and enters into

transactions with its subsidiaries, associates and other related companies on terms similar to those

offered to non-related parties. Intercompany balances and intercompany transactions have been

eliminated on consolidation, except for the net profit on certain transactions between non-regulated and

regulated entities in accordance with accounting standards for rate-regulated entities. All material

amounts are under normal interest and credit terms.

Significant transactions between Emera and its associated companies are as follows:

●

Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the

Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and

purchased power, totalling $

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.

●

Natural gas transportation capacity purchases from M&NP are reported in the Consolidated

Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated,

totalled $

million for the year ended December 31, 2023 (2022

– $

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.

18.

RECEIVABLES AND OTHER CURRENT ASSETS

As at

December 31

millions of dollars

2023

2022

Customer accounts receivable – billed

805

1,096

Capitalized transportation capacity

(1)

358

781

Customer accounts receivable – unbilled

363

424

Prepaid expenses

105

Income tax receivable

Allowance for credit losses

(15)

(17)

NMGC gas hedge settlement receivable

(2)

162

Other

191

360

Total receivables and other current assets

1,817

2,897

(1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management

agreements at the inception of the contracts. The asset is amortized over the term of each contract.

(2) Offsetting amount is included in regulatory liabilities for NMGC as gas hedges are part of the PGAC. For more information,

refer

to note 6.

19.

LEASES

Lessee

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

Emera’s leases have remaining lease terms of 1 year to 62 years, some of which include options to

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

considered reasonably certain they will be exercised.

Exhibit 99.3

As at

December 31

millions of dollars

Classification

2023

2022

Right-of-use asset

Other long-term assets

Lease liabilities

Current

Other current liabilities

Long-term

Other long-term liabilities

Total lease liabilities

The Company recorded lease expense of $

127

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

138

million), of which $

119

million (2022 – $

131

million) related to variable costs for power generation

facility finance leases, recorded in “Regulated fuel for generation and purchased power” in the

Consolidated Statements of Income.

Future minimum lease payments under non-cancellable operating leases for each of the next five years

and in aggregate thereafter are as follows:

millions of dollars

2024

2025

2026

2027

2028

Thereafter

Total

Minimum lease payments

111

131

Less imputed interest

(73)

Total

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

Year ended December 31

For the

2023

2022

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

Operating cash flows for operating leases (millions of dollars)

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

Operating leases (millions of dollars)

Weighted average remaining lease term (years)

Weighted average discount rate- operating leases

3.93%

3.98%

Lessor

The Company’s net investment in direct finance and sales-type leases primarily relates to Brunswick

Pipeline, Seacoast, compressed natural gas (“CNG”) stations, a renewable natural gas (“RNG”) facility

and heat pumps.

The Company manages its risk associated with the residual value of the Brunswick Pipeline lease

through proper routine maintenance of the asset.

Customers have the option to purchase CNG station assets by paying a make-whole payment at the date

of the purchase based on a targeted internal rate of return or may take possession of the CNG station

asset at the end of the lease term for no cost. Customers have the option to purchase heat pumps at the

end of the lease term for a nominal fee.

Commencing in October 2023, the Company leased a RNG facility to a biogas producer that is classified

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

15 years

, with a nominal value purchase at the end

of the term and a net investment of approximately $

million USD.

Commencing in January 2022, the Company leased Seacoast pipeline, a 21-mile, 30-inch lateral that is

classified as a sales-type lease. The term of the pipeline lateral lease is

years with a net investment of

100

million USD. The lessee of the pipeline lateral has renewal options for an additional

years. These

renewal options have not been included as part of the pipeline lateral lease term as it is not reasonably

certain that they will be exercised.

Exhibit 99.3

Direct finance and sales-type lease unearned income is recognized in income over the life of the lease

using a constant rate of interest equal to the internal rate of return on the lease and is recorded as

“Operating revenues – regulated gas” and “Other income, net” on the Consolidated Statements of

Income.

The total net investment in direct finance and sales-type leases consist of the following:

As at

December 31

millions of dollars

2023

2022

Total minimum lease payment to be received

1,360

1,393

Less: amounts representing estimated executory costs

(190)

(205)

Minimum lease payments receivable

1,170

1,188

Estimated residual value of leased property (unguaranteed)

183

Less: Credit loss reserve

(2)

Less: unearned finance lease income

(693)

(733)

Net investment in direct finance and sales-type leases

658

638

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

current assets")

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

621

604

As at December 31, 2023, future minimum lease payments to be received for each of the next five years

and in aggregate thereafter were as follows:

millions of dollars

2024

2025

2026

2027

2028

Thereafter

Total

Minimum lease payments to be

received

873

1,360

Less: executory costs

(190)

Total

1,170

20.

PROPERTY,

PLANT AND EQUIPMENT

PP&E consisted of the following regulated and non-regulated assets:

As at

December 31

millions of dollars

Estimated useful life

2023

2022

Generation

131

13,500

13,083

Transmission

2,835

2,731

Distribution

7,417

6,978

Gas transmission and distribution

5,536

5,061

General plant and other

(1)

2,985

2,723

Total cost

32,273

30,576

Less: Accumulated depreciation

(1)

(9,994)

(9,574)

22,279

21,002

Construction work in progress

(1)

2,097

1,994

Net book value

24,376

22,996

(1) SeaCoast owns a

% undivided ownership interest in a jointly owned

-mile pipeline lateral located in Florida, which went into

service in 2020. At December 31, 2023, SeaCoast’s share of plant in service was $

million USD (2022 – $

million USD), and

accumulated depreciation of $

million USD (2022 – $

million USD). SeaCoast’s undivided ownership interest is financed with its

funds and all operations are accounted for as if such participating interest were a wholly owned facility.

SeaCoast’s share of direct

expenses of the jointly owned pipeline is included in "OM&G" in the Consolidated Statements of Income.

21.

EMPLOYEE BENEFIT PLANS

Emera maintains a number of contributory defined-benefit (“DB”) and defined-contribution (“DC”) pension

plans, which cover substantially all of its employees. In addition, the Company provides non-pension

benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and

Labrador, Florida, New Mexico, Barbados, and Grand Bahama Island.

Exhibit 99.3

Emera’s net periodic benefit cost included the following:

Benefit Obligation and Plan Assets:

The changes in benefit obligation and plan assets, and the funded status for all plans were as follows:

For the

Year ended December 31

millions of dollars

2023

2022

Change in Projected Benefit Obligation

("PBO") and Accumulated Post-

retirement Benefit Obligation ("APBO")

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Balance, January 1

2,158

243

2,624

318

Service cost

Plan participant contributions

Interest cost

111

Plan amendments

(14)

Benefits paid

(147)

(29)

(174)

(31)

Actuarial losses (gains)

146

(480)

(79)

Settlements and curtailments

(8)

(6)

FX translation adjustment

(23)

(5)

Balance, December 31

2,273

227

2,158

243

Change in plan assets

Balance, January 1

2,163

2,702

Employer contributions

Plan participant contributions

Benefits paid

(147)

(29)

(174)

(31)

Actual return on assets, net of expenses

262

(489)

(7)

Settlements and curtailments

(8)

(6)

FX translation adjustment

(20)

(1)

Balance, December 31

2,298

2,163

Funded status, end of year

(179)

(197)

The actuarial losses recognized in the period are primarily due to changes in the discount rate, higher

than expected indexation, and compensation-related assumption changes.

Plans with PBO/APBO

in Excess of Plan Assets:

The aggregate financial position for all pension plans where the PBO or APBO (for post-retirement benefit

plans) exceeded the plan assets for the years ended December 31 was as follows:

millions of dollars

2023

2022

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

PBO/APBO

120

205

1,006

221

FV of plan assets

914

Funded status

(83)

(205)

(92)

(221)

Plans with Accumulated Benefit Obligation (“ABO”)

in Excess of Plan Assets:

The ABO for the DB pension plans was $

2,172

million as at December 31, 2023 (2022 – $

2,080

million).

The aggregate financial position for those plans with an ABO in excess of the plan assets for the years

ended December 31 was as follows:

millions of dollars

2023

2022

Defined benefit

pension plans

Defined benefit

pension plans

ABO

114

111

FV of plan assets

Funded status

(77)

(78)

Exhibit 99.3

Balance Sheet:

The amounts recognized in the Consolidated Balance Sheets consisted of the following:

As at

December 31

millions of dollars

2023

2022

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Other current liabilities

(5)

(18)

(13)

(20)

Long-term liabilities

(78)

(187)

(80)

(201)

Other long-term assets

108

AOCI, net of tax and regulatory assets

385

358

Less: Deferred income tax (expense)

recovery in AOCI

(8)

(1)

(7)

(1)

Net amount recognized

402

(160)

356

(176)

Amounts Recognized in AOCI and Regulatory Assets:

Unamortized gains and losses and past service costs arising on post-retirement benefits are recorded in

AOCI or regulatory assets. The following table summarizes the change in AOCI and regulatory assets:

Regulatory assets

Actuarial

(gains) losses

Past service

(gains) costs

millions of dollars

Defined Benefit Pension Plans

Balance, January 1, 2023

336

Amortized in current period

(6)

(3)

Current year additions

Change in FX rate

(7)

Balance, December 31, 2023

324

Non-pension benefits plans

Balance, January 1, 2023

(10)

Amortized in current period

Current year reductions

(3)

(1)

(3)

Change in FX rate

(1)

Balance, December 31, 2023

(8)

(2)

As at

December

millions of dollars

2023

2022

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Actuarial losses (gains)

(8)

(10)

Past service gains

(2)

Deferred income tax expense

AOCI, net of tax

(9)

Regulatory assets

324

336

AOCI, net of tax and regulatory assets

385

358

Exhibit 99.3

Benefit Cost Components:

Emera's net periodic benefit cost included the following:

As at

Year ended December 31

millions of dollars

2023

2022

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Service cost

Interest cost

111

Expected return on plan assets

(161)

(2)

(144)

Current year amortization of:

Actuarial losses (gains)

(3)

Regulatory assets (liability)

(2)

Settlement, curtailments

Total

(11)

The expected return on plan assets is determined based on the market-related value of plan assets of

2,577

million as at January 1, 2023 (2022 – $

2,482

million), adjusted for interest on certain cash flows

during the year.

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

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

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

Pension Plan Asset Allocations:

Emera’s investment policy includes discussion regarding the investment philosophy, the level of risk

which the Company is prepared to accept with respect to the investment of the Pension Funds, and the

basis for measuring the performance of the assets. Central to the policy is the target asset allocation by

major asset categories. The objective of the target asset allocation is to diversify risk and to achieve asset

returns that meet or exceed the plan’s actuarial assumptions. The diversification of assets reduces the

inherent risk in financial markets by requiring that assets be spread out amongst various asset classes.

Within each asset class, a further diversification is undertaken through the investment in a broad range of

investment and non-investment grade securities. Emera’s target asset allocation is as follows:

Canadian Pension Plans

Asset Class

Target Range at Market

Short-term securities

10%

Fixed income

34%

49%

Equities:

Canadian

17%

Non-Canadian

35%

59%

Non-Canadian Pension Plans

Asset Class

Target Range at Market

Weighted average

Cash and cash equivalents

10%

Fixed income

29%

49%

Equities

48%

68%

Pension Plan assets are overseen by the respective Management Pension Committees in the sponsoring

companies. All pension investments are in accordance with policies approved by the respective Board of

Directors of each sponsoring company.

Exhibit 99.3

The following tables set out the classification of the methodology used by the Company to FV its

investments:

millions of dollars

NAV

Level 1

Level 2

Total

Percentage

As at

December 31, 2023

Cash and cash equivalents

Net in-transits

(9)

Equity securities:

Canadian equity

United States equity

141

Other equity

112

Fixed income securities:

Government

172

Corporate

Other

Mutual funds

Other

(1)

Open-ended investments

measured at NAV

(1)

1,006

Common collective trusts

measured at NAV

(2)

586

Total

1,592

440

266

2,298

100

As at

December 31, 2022

Cash and cash equivalents

Net in-transits

(70)

(3)

Equity securities:

Canadian equity

United States equity

233

Other equity

186

Fixed income securities:

Government

104

Corporate

Other

Mutual funds

Other

(3)

Open-ended investments

measured at NAV

(1)

790

Common collective trusts

measured at NAV

(2)

601

Total

1,391

577

195

2,163

100

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

registered and non-registered mutual funds, collective investment trusts,

or pooled funds. NAV’s are calculated

at least monthly and the funds honour subscription and redemption activity regularly.

(2) The common collective trusts are private funds valued at NAV.

The NAVs are calculated based on bid prices

of the underlying

securities. Since the prices are not published to external sources, NAV

is used as a practical expedient. Certain funds invest

primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment grade fixed

income assets and seeks to increase return through active management of interest rate and credit risks. The funds honour

subscription and redemption activity regularly.

Refer to note 16 for more information on the FV hierarchy and inputs used to measure FV.

Post-Retirement Benefit Plans:

There are no assets set aside to pay for most of the Company’s post-retirement benefit plans. As is

common practice, post-retirement health benefits are paid from general accounts as required. The

primary exception to this is the NMGC Retiree Medical Plan, which is fully funded.

Exhibit 99.3

Investments in Emera:

As at December 31, 2023 and 2022, assets related to the pension funds and post-retirement benefit plans

did not hold any material investments in Emera or its subsidiaries securities. However, as a significant

portion of assets for the benefit plan are held in pooled assets, there may be indirect investments in these

securities.

Cash Flows:

The following table shows expected cash flows for DB pension and other post-retirement benefit plans:

millions of dollars

Defined benefit

pension plans

Non-pension

benefit plans

Expected employer contributions

2024

Expected benefit payments

2024

172

2025

163

2026

166

2027

171

2028

173

2029 – 2033

890

Assumptions:

The following table shows the assumptions that have been used in accounting for DB pension and other

post-retirement benefit plans:

2023

2022

(weighted average assumptions)

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Benefit obligation – December 31:

Discount rate - past service

4.89

5.33

5.31

Discount rate - future service

4.88

4.89

5.34

5.32

Rate of compensation increase

3.87

3.85

3.62

3.61

Health care trend

- initial (next year)

6.04

5.40

- ultimate

3.76

3.77

- year ultimate reached

2043

Benefit cost for year ended December 31:

Discount rate - past service

5.33

5.31

3.05

2.81

Discount rate - future service

5.34

5.32

3.18

2.92

Expected long-term return on plan assets

6.56

2.16

6.07

1.32

Rate of compensation increase

3.62

3.61

3.31

3.29

Health care trend

- initial (current year)

5.40

5.09

- ultimate

3.77

- year ultimate reached

2043

2042

Actual assumptions used differ by plan.

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

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

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

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

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

The discount rate is based on high-quality long-term corporate bonds, with maturities matching the

estimated cash flows from the pension plan.

Defined Contribution Plan:

Emera also provides a DC pension plan for certain employees. The Company’s contribution for the year

ended December 31, 2023 was $

million (2022 – $

million).

Exhibit 99.3

22.

GOODWILL

The change in goodwill for the year ended December 31 was due to the following:

millions of dollars

2023

2022

Balance, January 1

6,012

5,696

Change in FX rate

(141)

389

GBPC impairment charge

(73)

Balance, December 31

5,871

6,012

Goodwill is subject to an annual assessment for impairment at the reporting unit level. The goodwill on

Emera’s Consolidated Balance Sheets at December 31, 2023, primarily related to TECO Energy

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

In 2023, Emera performed qualitative impairment assessments for NMGC and PGS, concluding that the

FV of the reporting units exceeded their respective carrying amounts, and as such, no quantitative

assessments were performed and

impairment charges were recognized. 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 approach and market approach. This assessment estimated that the FV of the

TEC reporting unit exceeded its carrying amount, including goodwill, and as a result

impairment

charges were recognized.

In 2022, the Company elected to bypass a qualitative assessment and performed a quantitative

impairment assessment for GBPC, using the income approach. It was determined that the FV did not

exceed its carrying amount, including goodwill. As a result of this assessment, a goodwill impairment

charge of $

million was recorded in 2022, reducing the GBPC goodwill balance to nil as at December

31, 2022. This non-cash charge is included in “GBPC impairment charge” on the Consolidated

Statements of Income.

23.

SHORT-TERM DEBT

Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non-

revolving credit facilities and short-term notes. Short-term debt and the related weighted-average interest

rates as at December 31 consisted of the following:

millions of dollars

2023

Weighted

average

interest rate

2022

Weighted

average

interest rate

TEC

Advances on revolving credit facilities

277

5.68

1,380

5.00

Emera

Non-revolving term facilities

796

6.07

796

5.19

Bank indebtedness

TECO Finance

Advances on revolving credit and term facilities

245

6.54

481

5.47

PGS

Advances on revolving credit facilities

6.36

NMGC

Advances on revolving credit facilities

6.46

5.15

GBPC

Advances on revolving credit facilities

5.54

5.25

Short-term debt

1,433

2,726

Exhibit 99.3

The Company’s total short-term revolving and non-revolving credit facilities, outstanding borrowings and

available capacity as at December 31 were as follows:

millions of dollars

Maturity

2023

2022

TEC - Unsecured committed revolving credit facility

2026

401

1,084

TECO Energy/TECO Finance - revolving credit facility

2026

542

TECO Finance - Unsecured committed revolving credit facility

2026

529

Emera - Unsecured non-revolving term facility

2024

400

Emera - Unsecured non-revolving term facility

2024

400

PGS - Unsecured revolving credit facility

2028

331

TEC - Unsecured revolving facility

2024

265

542

TEC - Unsecured revolving facility

2024

265

NMGC - Unsecured revolving credit facility

2026

165

169

Other - Unsecured committed revolving credit facilities

Various

Total

2,773

3,155

Less:

Advances under revolving credit and term facilities

1,433

2,731

Letters of credit issued within the credit facilities

Total advances under available facilities

1,436

2,735

Available capacity under existing agreements

1,337

420

The weighted average interest rate on outstanding short-term debt at December 31, 2023 was

5.95

per

cent (2022 –

5.01

per cent).

Recent Significant Financing Activity by Segment

Florida Electric Utilities

On November 24, 2023, TEC repaid its $

400

million USD unsecured non-revolving facility, which expired

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.

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.

Gas Utilities and Infrastructure

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.

Exhibit 99.3

Other

On December 16, 2023, Emera amended its $

400

million unsecured non-revolving facility to extend the

maturity date from

December 16, 2023

December 16, 2024

. There were no other changes in

commercial terms from the prior agreement.

On June 30, 2023, Emera amended its $

400

million unsecured non-revolving facility to extend the

maturity date from

August 2, 2023

August 2, 2024

. There were no other changes in commercial terms

from the prior agreement.

24.

OTHER CURRENT LIABILITIES

As at

December 31

millions of dollars

2023

2022

Accrued charges

172

174

Nova Scotia Cap-and-Trade Program provision (note 6)

172

Accrued interest on long-term debt

107

Pension and post-retirement liabilities (note 21)

Sales and other taxes payable

Income tax payable

Other

112

427

579

Exhibit 99.3

25.

LONG-TERM DEBT

Bonds, notes and debentures are at fixed interest rates and are unsecured unless noted below. Included

are certain bankers’ acceptances and commercial paper where the Company has the intention and the

unencumbered ability to refinance the obligations for a period greater than one year.

Long-term debt as at December 31 consisted of the following:

Weighted average interest

rate

(1)

millions of dollars

2023

2022

Maturity

2023

2022

Emera

Bankers acceptances, SOFR loans

Variable

2027

465

403

Unsecured fixed rate notes

4.84%

2.90%

2030

500

Fixed to floating subordinated notes

(2)

6.75%

2076

1,587

1,625

2,552

2,528

Emera Finance

Unsecured senior notes

3.65%

2024 - 2046

3,637

3,725

TEC

(3)

Fixed rate notes and bonds

4.61%

4.15%

2024 - 2051

5,654

4,341

PGS

Fixed rate notes and bonds

5.63%

3.78%

2028 - 2053

1,223

772

NMGC

Fixed rate notes and bonds

3.78%

3.11%

2026 - 2051

642

521

Non-revolving term facility, floating rate

Variable

2024

108

672

629

NMGI

Fixed rate notes and bonds

3.64%

2024

198

203

NSPI

Discount Notes

(4)

Variable

2024 - 2027

721

881

Medium term fixed rate notes

5.13%

5.14%

2025 - 2097

3,165

2,665

3,886

3,546

EBP

Senior secured credit facility

Variable

2026

246

249

ECI

Secured senior notes

Variable

2027

Amortizing fixed rate notes

4.00%

3.97%

2026

100

Non-revolving term facility, floating rate

Variable

2025

Non-revolving term facility, fixed rate

2.15%

2.05%

2025 - 2027

155

Secured fixed rate senior notes

(5)

3.09%

3.06%

2024 - 2029

142

422

449

Adjustments

Fair market value adjustment - TECO Energy acquisition

Debt issuance costs

(125)

(126)

Amount due within one year

(676)

(574)

(801)

(698)

Long-Term Debt

17,689

15,744

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

(2) In 2023, the Company recognized $

109

million in interest expense (2022 – $

110

million) related to its fixed to floating

subordinated notes.

(3) A substantial part of TEC’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently

bonds outstanding under TEC’s first mortgage bond indenture.

(4) Discount notes are backed by a revolving credit facility which matures in 2027. Banker’s acceptances are issued under NSPI’s

non-revolving term facility which matures in 2024. NSPI has the intention and unencumbered ability to refinance bankers’

acceptances for a period of greater than one year.

(5) Notes are issued and payable in either USD or BBD.

Exhibit 99.3

The Company’s total long-term revolving credit facilities, outstanding borrowings and available capacity as

at December 31 were as follows:

millions of dollars

Maturity

2023

2022

Emera – revolving credit facility

(1)

June 2027

900

TEC - Unsecured committed revolving credit facility

December 2026

657

NSPI - revolving credit facility

(1)

December 2027

800

NSPI - non-revolving credit facility

July 2024

400

Emera - Unsecured non-revolving credit facility

February 2024

400

NMGC - Unsecured non-revolving credit facility

March 2024

108

ECI – revolving credit facilities

October 2024

Total

3,197

2,219

Less:

Borrowings under credit facilities

1,884

1,396

Letters of credit issued inside credit facilities

Use of available facilities

1,890

1,408

Available capacity under existing agreements

1,307

811

(1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $

million.

Debt Covenants

Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are

tested regularly and the Company is in compliance with covenant requirements. Emera’s significant

covenants are listed below:

As at

Financial Covenant

Requirement

December 31, 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 by Segment

Florida Electric Utility

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

repayment of short-term borrowings outstanding under the

-year credit facility. Therefore, $

497

million

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

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

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

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

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

Exhibit 99.3

Other Electric Utilities

On May 24, 2023, GBPC issued a $

million USD non-revolving term loan that bears interest at

4.00

per

cent with a maturity date of

May 24, 2028

Other

On August 18, 2023, Emera entered into a $

400

million non-revolving term facility with a maturity date of

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. On February 16, 2024, Emera extended the term of this agreement to a

maturity date of

February 19, 2025

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

Long-Term Debt Maturities

As at December 31, long-term debt maturities, including capital lease obligations, for each of the next five

years and in aggregate thereafter are as follows:

millions of dollars

2024

2025

2026

2027

2028

Thereafter

Total

Emera

199

1,587

266

500

2,552

Emera US Finance LP

397

992

2,248

3,637

TEC

397

5,257

5,654

PGS

463

760

1,223

NMGC

549

672

NMGI

198

NSPI

398

125

323

3,000

3,886

EBP

246

ECI

139

422

Total

1,670

264

3,047

666

525

12,318

18,490

26.

ASSET RETIREMENT OBLIGATIONS

AROs mostly relate to reclamation of land at the thermal, hydro and combustion turbine sites; and the

disposal of polychlorinated biphenyls in transmission and distribution equipment and a pipeline site.

Certain hydro, transmission and distribution assets may have additional AROs that cannot be measured

as these assets are expected to be used for an indefinite period and, as a result, a reasonable estimate of

the FV of any related ARO cannot be made.

The change in ARO for the years ended December 31 is as follows:

millions of dollars

2023

2022

Balance, January 1

174

Accretion included in depreciation expense

Change in FX rate

(1)

Additions

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

Liabilities settled

(8)

(1)

Revisions in estimated cash flows

(13)

Balance, December 31

192

174

Exhibit 99.3

27.

COMMITMENTS AND CONTINGENCIES

Commitments

As at December 31, 2023, contractual commitments (excluding pensions and other post-retirement

obligations, long-term debt and asset retirement obligations) for each of the next five years and in

aggregate thereafter consisted of the following:

millions of dollars

2024

2025

2026

2027

2028

Thereafter

Total

Transportation

(1)

696

495

405

388

338

2,597

4,919

Purchased power

(2)

274

249

263

312

3,435

4,845

Fuel, gas supply and storage

556

215

838

Capital projects

778

111

960

Equity investment commitments

(3)

240

Other

154

147

221

659

2,698

1,217

856

747

690

6,253

12,461

(1) 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.

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

(3) 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 the collection of up to $

164

million from NSPI for the recovery of Maritime Link costs in

2024. The timing and amounts payable to NSPML for the remainder of the

-year commitment period

are subject to UARB approval.

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

700

MW, 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.

Legal Proceedings

Superfund and Former Manufactured Gas Plant Sites

Previously, TEC had been a potentially responsible party (“PRP”) for certain superfund sites through its

Tampa

Electric and former PGS divisions, as well as for certain former manufactured gas plant sites

through its PGS division. As a result of the separation of the PGS division into a separate legal entity,

Peoples Gas System, Inc. is also now a PRP for those sites (in addition to third party PRPs for certain

sites).

While the aggregate joint and several liability associated with these sites has not changed as a

result of the PGS legal separation, the sites continue to present the potential for significant response

costs. As at December 31, 2023, the aggregate financial liability of the Florida utilities is estimated to be

million ($

million USD), primarily at PGS. This estimate assumes that other involved PRPs are

credit-worthy entities. This amount has been accrued and is primarily reflected in the long-term liability

section under “Other long-term liabilities” on the Consolidated Balance Sheets. The environmental

remediation costs associated with these sites are expected to be paid over many years.

Exhibit 99.3

The estimated amounts represent only the portion of the cleanup costs attributable to the Florida utilities.

The estimates to perform the work are based on the Florida utilities’ experience with similar work,

adjusted for site-specific conditions and agreements with the respective governmental agencies. The

estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-

worthy and are likely to continue to be credit-worthy for the duration of the remediation work. However, in

those instances that they are not, the Florida utilities could be liable for more than their actual percentage

of the remediation costs. Other factors that could impact these estimates include additional testing and

investigation which could expand the scope of the cleanup activities, additional liability that might arise

from the cleanup activities themselves or changes in laws or regulations that could require additional

remediation. Under current regulations, these costs are recoverable through customer rates established

in base rate proceedings.

Other Legal Proceedings

Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and

litigation that arise in the ordinary course of business which the Company believes would not reasonably

be expected to have a material adverse effect on the financial condition of the Company.

Principal Financial Risks and Uncertainties

Emera believes the following principal financial risks could materially affect the Company in the normal

course of business. Risks associated with derivative instruments and FV measurements are discussed in

note 15 and note 16.

Sound risk management is an essential discipline for running the business efficiently and pursuing the

Company’s strategy successfully. Emera has an enterprise-wide risk management process, overseen by

its Enterprise Risk Management Committee (“ERMC”) and monitored by the Board of Directors, to ensure

an effective, consistent and coherent approach to risk management. The Board of Directors has a Risk

and Sustainability Committee (‘RSC”) with a mandate that 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.

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.

Exhibit 99.3

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.

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.

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.

The Company does not utilize derivative financial instruments for foreign currency trading or speculative

purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on

net investments in foreign subsidiaries do not impact net income as they are reported in AOCI.

Exhibit 99.3

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.

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.

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.

Exhibit 99.3

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.

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.

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.

Exhibit 99.3

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.

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.

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 $

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 that TECO Energy’s and Emera’s long-term senior unsecured credit ratings are downgraded

below investment grade by Moody’s Investor Services (“Moody’s”) or S&P Global Ratings (“S&P”). TECO

Energy would be required to provide its counterparty a letter of credit or cash deposit of $

million USD.

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

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

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

potential amount of $

million USD if SeaCoast fails to pay or perform under the firm service agreement.

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 $

million

USD.

Emera Inc. has issued a guarantee of $

million USD relating to outstanding notes of ECI. This

guarantee will automatically terminate on the date upon which the obligations have been repaid in full.

NSPI has 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.

Exhibit 99.3

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 $

million (December 31, 2022 – $

million).

Collaborative Arrangements

For the years ended December 31, 2023 and 2022, the Company has identified the following material

collaborative arrangements:

Through NSPI, the Company is a participant in three wind energy projects in Nova Scotia. The

percentage ownership of the wind project assets is based on the relative value of each party’s project

assets by the total project assets. NSPI has power purchase arrangements to purchase the entire net

output of the projects and, therefore, NSPI’s portion of the revenues are recorded net within regulated fuel

for generation and purchased power. NSPI’s portion of operating expenses is recorded in “OM&G” on the

Consolidated Statements of Income. In 2023, NSPI recognized $

million net expense (2022 – $

million) in “Regulated fuel for generation and purchased power” and $

million (2022 – $

million) in

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

28.

CUMULATIVE PREFERRED STOCK

Authorized:

Unlimited number of First Preferred shares, issuable in series.

Unlimited number of Second Preferred shares, issuable in series.

December 31, 2023

December 31, 2022

Annual Dividend

Redemption

Issued and

Net

Issued and

Net

Per Share

Price per share

Outstanding

Proceeds

Outstanding

Proceeds

Series A

0.5456

25.00

4,866,814

119

4,866,814

119

Series B

Floating

25.00

1,133,186

Series C

1.6085

25.00

10,000,000

245

10,000,000

245

Series E

1.1250

25.00

5,000,000

122

5,000,000

122

Series F

1.0505

25.00

8,000,000

195

8,000,000

195

Series H

1.5810

25.00

12,000,000

295

12,000,000

295

Series J

1.0625

25.00

8,000,000

196

8,000,000

196

Series L

1.1500

26.00

9,000,000

222

9,000,000

222

Total

58,000,000

1,422

58,000,000

1,422

Exhibit 99.3

Characteristics of the First Preferred Shares:

First Preferred Shares

(1)(2)

Initial Yield

(%)

Current

Annual

Dividend

($)

Minimum

Reset

Dividend

Yield (%)

Earliest Redemption

and/or Conversion

Option Date

Redemption

Value

($)

Right to

Convert on

a one for

one basis

Fixed rate reset

(3)(4)

Series A

4.400

0.5456

1.84

August 15, 2025

25.00

Series B

Series C

(5)(6)

4.100

1.6085

2.65

August 15, 2028

25.00

Series D

Series F

4.202

1.0505

2.63

February 15, 2025

25.00

Series G

Minimum rate reset

(3)(4)

Series B

2.393

Floating

1.84

August 15, 2025

25.00

Series A

Series H

(5)(7)

4.900

1.5810

4.90

August 15, 2028

25.00

Series I

Series J

4.250

1.0625

4.25

May 15, 2026

25.00

Series K

Perpetual fixed rate

Series E

(8)

4.500

1.1250

25.00

Series L

(9)

4.600

1.1500

November 15, 2026

26.00

(1) Holders are entitled to receive fixed or floating cumulative cash dividends when declared by the Board of Directors of the

Corporation.

(2) On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding First

Preferred

Shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but

excluding the

dates fixed for redemption.

(3) On the redemption and/or conversion option date the reset annual dividend per share will be determined by multiplying

25.00

per

share by the annual fixed or floating dividend rate, which for Series A, C, F and H is the sum of the five-year Government

of Canada

Bond Yield on the applicable reset date, plus the applicable reset dividend yield

(Series H annual reset rate must be a minimum of

4.90

per cent) and for Series B equals the Government of Treasury Bill Rate on the applicable

reset date, plus 1.84 per cent.

(4) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their

into an equal number of Cumulative Redeemable First Preferred Shares of a specified series. The Company has the right

to redeem

the outstanding Preferred Shares, Series D, Series G and Series I shares without the consent of the holder every five years

thereafter

for cash, in whole or in part at a price of $

25.00

per share plus all accrued and unpaid dividends up to but excluding the date fixed for

redemption and $

25.50

per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case

of redemptions on any other date after August 15, 2028, February 15, 2025 and August 15, 2028, respectively.

The reset dividend

yield for Series I equals the Government of Treasury Bill Rate on the applicable reset date, plus

2.54

per cent.

(5) On July 6, 2023, Emera announced it would not redeem the outstanding Preferred Shares, Series C and Series

H 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 Series D Shares and no Series H Shares were converted into Series I shares.

(6) The annual fixed dividend per share for Series C Shares was reset from $

1.1802

to $

1.6085

for the five-year period from and

including August 15, 2028.

(7) The annual fixed dividend per share for Series H Shares was reset from $

1.2250

to $

1.5810

for the five-year period from and

including August 15, 2028.

(8) First Preferred Shares, Series E are redeemable at $25.00 per share.

(9) First Preferred Shares, Series L are redeemable at $

26.00

on or after November 15, 2026 to November 15, 2027, decreasing

0.25

each year until November 15, 2030 and $

25.00

per share thereafter.

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

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

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

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

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

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

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

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

dissolution or wind-up, whether voluntary or involuntary.

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

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

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

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

meeting.

Exhibit 99.3

29.

NON-CONTROLLING INTEREST IN SUBSIDIARIES

As at

December 31

millions of dollars

2023

2022

Preferred shares of GBPC

Preferred shares of GBPC:

Authorized:

10,000

non-voting cumulative redeemable variable perpetual preferred shares.

2023

2022

Issued and outstanding:

number of

millions of

dollars

number of

millions of

dollars

Outstanding as at December 31

10,000

GBPC Non–Voting Cumulative Variable Perpetual Preferred Stock:

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

, at $

1,000

Bahamian per share plus

accrued and unpaid dividends and are entitled to a

6.0 per cent per annum fixed cumulative preferential

dividend to be paid semi-annually

The Preferred Shares rank behind GBPC’s current and future secured and unsecured debt and ahead of

all of GBPC’s current and future common stock.

30. SUPPLEMENTARY

INFORMATION TO

CONSOLIDATED STATEMENTS

CASH FLOWS

For the

Year ended December 31

millions of dollars

2023

2022

Changes in non-cash working capital:

Inventory

(31)

(214)

Receivables and other current assets

(1)

653

(636)

Accounts payable

(538)

423

Other current liabilities

(2)

(179)

193

Total non-cash working capital

(95)

(234)

(1) Includes $

162

million related to the January 2023 settlement of NMGC gas hedges (2022 – ($

162

) million). Offsetting regulatory

liability is included in operating cash flow before working capital resulting in no impact to net cash provided by operating activities.

(2) Includes ($

166

) million related to the Nova Scotia Cap-and-Trade program (2022 – $

172

million). For further detail, refer to note

6. Offsetting regulatory asset (FAM) balance is

included in operating cash flow before working capital resulting in no impact to net

cash provided by operating activities.

For the

Year ended December 31

millions of dollars

2023

2022

Supplemental disclosure of cash paid:

Interest

930

699

Income taxes

Supplemental disclosure of non-cash activities:

Common share dividends reinvested

271

237

Decrease in accrued capital expenditures

(19)

(13)

Reclassification of short-term debt to long-term debt

657

Reclassification of long-term debt to short-term debt

500

Supplemental disclosure of operating activities:

Net change in short-term regulatory assets and liabilities

123

(157)

Exhibit 99.3

31.

STOCK-BASED COMPENSATION

Employee Common Share Purchase Plan and Common Shareholders Dividend

Reinvestment and Share Purchase Plan

Eligible employees may participate in the ECSPP. As of December 31, 2023, the plan allows employees

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

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

the employees’ contributions to the plan.

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

The

maximum aggregate number of Emera common shares reserved for issuance under this plan is

million

common shares. As at December 31, 2023, Emera was in compliance with this requirement.

Compensation cost for shares issued under the ECSPP for the year ended December 31, 2023 was $

million (2022 – $

million) and was included in “OM&G” on the Consolidated Statements of Income.

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

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

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

purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2023.

Stock-Based Compensation Plans

Stock Option Plan

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

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

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

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

issuable under this plan is 14.7 million shares. As at December 31, 2023, Emera was in compliance with

this requirement.

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

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

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

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

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

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

outstanding common stocks on the date the option is granted.

For stock options granted in 2021 and prior, unless a stock option has expired, vested options may be

exercised within the

27 months

following the option holder’s date of retirement,

six months

following a

termination without just cause or death, and within

sixty days

following the date of termination for just

cause or resignation. Commencing with the 2022 stock option grant, vested options may be exercised

during the full term of the option following the option holders date of retirement,

six months

following a

termination without just cause or death, and within

sixty days

following the date of termination for just

cause or resignation. If stock options are not exercised within such time, they expire.

The Company uses the Black-Scholes valuation model to estimate the compensation expense related to

its stock-based compensation and recognizes the expense over the vesting period on a straight-line

basis.

The following table shows the weighted average FV per stock option along with the assumptions

incorporated into the valuation models for options granted, for the year-ended December 31:

Exhibit 99.3

2023

2022

Weighted average FV per option

6.32

5.35

Expected term

(1)

years

Risk-free interest rate

(2)

3.53

1.79

Expected dividend yield

(3)

5.05

4.55

Expected volatility

(4)

20.07

18.87

(1) The expected term of the option awards is calculated based on historical exercise behaviour and represents the period

of time

that the options are expected to be outstanding.

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

(3) Incorporates current dividend rates and historical dividend increase patterns.

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

The following table summarizes stock option information for 2023:

Total Options

Non-Vested Options

(1)

Number of

Options

Weighted

average exercise

price per share

Number of

Options

Weighted

average grant

date fair-value

Outstanding as at December 31, 2022

2,853,879

50.41

1,348,400

4.08

Granted

483,100

54.64

483,100

6.32

Exercised

(146,475)

43.94

N/A

Forfeited

(94,900)

56.32

(51,625)

3.61

Vested

N/A

(526,620)

3.58

Options outstanding December 31, 2023

3,095,604

51.20

1,253,255

5.17

Options exercisable December 31, 2023

(2)(3)

1,842,349

48.39

(1) As at December 31, 2023, there was $

million of unrecognized compensation related to stock options not yet vested which is

expected to be recognized over a weighted average period of approximately

years (2022 – $

million,

years).

(2) As at December 31, 2023, the weighted average remaining term of vested options was

years with an aggregate intrinsic value of

million (2022 –

years, $

million).

(3) As at December 31, 2023, the FV of options that vested in the year was $

million (2022 – $

million).

Compensation cost recognized for stock options for the year ended December 31, 2023 was $

million

(2022 – $

million), which was included in “OM&G” on the Consolidated Statements of Income.

As at December 31, 2023, cash received from option exercises was $

million (2022 – $

million). The

total intrinsic value of options exercised for the year ended December 31, 2023 was $

million (2022 – $

million). The range of exercise prices for the options outstanding as at December 31, 2023 was $

32.35

60.03

(2022 – $

32.35

to $

60.03

Share Unit Plans

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

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

Deferred Share Unit Plans

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

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

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

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

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

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

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

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

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

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

redeemed.

Exhibit 99.3

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

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

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

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

the applicable guidelines are met.

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

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

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

dividends paid on an equivalent number of Emera common shares. Following termination of employment

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

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

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

given calculation date. Payments are made in cash.

In addition, special DSU awards may be made from time to time by the Management Resources and

Compensation Committee (“MRCC”), to selected executives and senior management to recognize

singular achievements or by achieving certain corporate objectives.

A summary of the activity related to employee and director DSUs for the year ended December 31, 2023

is presented in the following table:

Employee

DSU

Weighted

Average

Grant Date

Director

DSU

Weighted

Average

Grant Date

Outstanding as at December 31, 2022

627,223

41.55

664,258

45.83

Granted including DRIP

85,740

47.66

117,893

49.99

Exercised

N/A

(53,093)

49.39

Outstanding and exercisable as at December 31, 2023

712,963

42.29

729,058

46.24

Compensation cost recovery recognized for employee and director DSU’s for the year ended December

31, 2023 was $

million (2022 – $

million). Tax

expense related to this compensation cost recovery for

share units realized for the year ended December 31, 2023 was $

million (2022 – $

million). The

aggregate intrinsic value of the outstanding shares for the year ended December 31, 2023 for employees

was $

million (2022 – $

million). The aggregate intrinsic value of the outstanding shares for the year

ended December 31, 2023 for directors was $

million (2022 – $

million). Cash payments made

during the year ended December 31, 2023 associated with the DSU plan were $

million (2022 – $

million).

Performance Share Unit Plan

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

through the plan. PSUs are granted annually for three-year overlapping performance cycles, resulting in a

cash payment. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading

days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional

PSUs. The PSU value varies according to the Emera common share market price and corporate

performance.

PSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the

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

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

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

Exhibit 99.3

A summary of the activity related to employee PSUs for the year ended December 31, 2023 is presented

in the following table:

Employee PSU

Weighted Average

Grant Date FV

Aggregate intrinsic value

Outstanding as at December 31, 2022

690,446

56.24

Granted including DRIP

386,261

52.71

Exercised

(323,155)

54.62

Forfeited

(10,187)

55.15

Outstanding as at December 31, 2023

743,365

55.13

Compensation cost recognized for the PSU plan for the year ended December 31, 2023 was $

million

(2022 – $

million). Tax

benefits related to this compensation cost for share units realized for the year

ended December 31, 2023 were $

million (2022 – $

million). Cash payments made during the year

ended December 31, 2023 associated with the PSU plan were $

million (2022 – $

million).

Restricted Share Unit Plan

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

through the plan. RSUs are granted annually for three-year overlapping performance cycles, resulting in a

cash payment. RSUs are granted based on the average of Emera’s stock closing price for the fifty trading

days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional

RSUs. The RSU value varies according to the Emera common share market price.

RSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the

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

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

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

A summary of the activity related to employee RSUs for the year ended December 31, 2023 is presented

in the following table:

Employee RSU

Weighted Average

Grant Date FV

Aggregate intrinsic value

Outstanding as at December 31, 2022

508,468

56.25

Granted including DRIP

236,537

52.07

Exercised

(171,537)

54.62

Forfeited

(10,827)

54.76

Outstanding as at December 31, 2023

562,641

55.01

Compensation cost recognized for the RSU plan for the year ended December 31, 2023 was $

million

(2022 – $

million). Tax

benefits related to this compensation cost for share units realized for the year

ended December 31, 2023 were $

million (2022 – $

million). Cash payments made during the year

ended December 31, 2023 associated with the RSU plan were $

million (2022–

nil

32.

VARIABLE INTEREST ENTITIES

Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the

primary beneficiary since it does not have the controlling financial interest of NSPML. When the critical

milestones were achieved, Nalcor Energy was deemed the primary beneficiary of the asset for financial

reporting purposes as it has authority over the majority of the direct activities that are expected to most

significantly impact the economic performance of the Maritime Link. Thus, Emera began recording the

Maritime Link as an equity investment.

Exhibit 99.3

BLPC has established a SIF, primarily for the purpose of building a fund to cover risk against damage and

consequential loss to certain generating, transmission and distribution systems. ECI holds a variable

interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the

SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered

that, in substance, the activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and

BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC,

has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF.

Any withdrawal of SIF fund assets by the Company would be subject to existing regulations. Emera’s

consolidated VIE in the SIF is recorded as “Other long-term assets”, “Restricted cash” and “Regulatory

liabilities” on the Consolidated Balance Sheets. Amounts included in restricted cash represent the cash

portion of funds required to be set aside for the BLPC SIF.

The Company has identified certain long-term purchase power agreements that meet the definition of

variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed

price. However, it was determined that the Company was not the primary beneficiary since it lacked the

power to direct the activities of the entity, including the ability to operate the generating facilities and make

management decisions.

The following table provides information about Emera’s portion of material unconsolidated VIEs:

As at

December 31, 2023

December 31, 2022

Maximum

millions of dollars

Total

assets

exposure to

loss

Total

assets

exposure to

loss

Unconsolidated VIEs in which Emera has variable interests

NSPML (equity accounted)

489

501

33.

SUBSEQUENT EVENTS

These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to

the balance sheet date through February 26, 2024, the date the financial statements were issued.