EX-99.3

EMERA INCORPORATED

Consolidated

Financial Statements

December 31, 2022 and 2021

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 23, 2023

“Scott Balfour”

“Gregory Blunden”

President and Chief Executive Officer

Chief Financial Officer

Report of Independent Registered Public Accounting Firm

the Shareholders and the Board of Directors of Emera Incorporated

Opinion on the Consolidated Financial Statements

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

“Company“) as of December 31, 2022 and 2021, 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, 2022 and 2021, and the consolidated results of its operations and its consolidated cash

flows for each of the two years in the period ended December 31, 2022, in conformity with United States

generally accepted accounting principles.

Basis for Opinion

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

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

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

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

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

and Exchange Commission and the PCAOB.

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

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

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

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

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

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

financial reporting. Accordingly, we express no such opinion.

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

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

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

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

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

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

basis for our opinion.

Critical Audit Matters

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

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

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

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

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

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

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

Accounting for the effects of rate regulation

Description of the

Matter

As disclosed in note 7 of the consolidated financial statements, the

Company has $3.6 billion in regulatory assets and $2.3 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 to 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 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

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 measurement of derivative financial instruments

Description of the

Matter

Held-for-trading (“HFT”) derivative assets of $429 million and liabilities of

$1,301 million, disclosed in note 15 to the consolidated financial statements,

are measured at fair value. The Company recognized $64 million in realized

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

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

judgmental due to the complexity of the contract terms and valuation

models, and the significant estimation required in determining the fair value

of the contracts. In determining the fair value 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

fair value 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 fair value 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 fair value of

derivatives.

/s/ Ernst & Young LLP

Chartered Professional Accountants

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

Halifax, Canada

February 23, 2023

Emera Incorporated

Consolidated Statements of Income

For the

Year ended December 31

millions of dollars (except per share amounts)

2022

2021

Operating revenues

Regulated electric

5,473

4,665

Regulated gas

1,681

1,261

Non-regulated

434

(161)

Total operating revenues (note 6)

7,588

5,765

Operating expenses

Regulated fuel for generation and purchased power

2,171

1,763

Regulated cost of natural gas

800

472

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

1,596

1,368

Provincial, state, and municipal taxes

367

330

Depreciation and amortization

952

902

Impairment charge (note 22)

Total operating expenses

5,959

4,835

Income from operations

1,629

930

Income from equity investments (note 8)

129

143

Other income, net (note 9)

145

Interest expense, net

709

611

Income before provision for income taxes

1,194

555

Income tax expense (recovery) (note 10)

185

(6)

Net income

1,009

561

Non-controlling interest in subsidiaries

Preferred stock dividends

Net income attributable to common shareholders

945

510

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

Basic

266

257

Diluted

266

258

Earnings per common share (note 12)

Basic

3.56

1.98

Diluted

3.55

1.98

Dividends per common share declared

2.6775

2.5750

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

Emera Incorporated

Consolidated Statements of Comprehensive Income

For the

Year ended December 31

millions of dollars

2022

2021

Net income

1,009

561

Other comprehensive income (loss), net of tax

Foreign currency translation adjustment

(1)

629

(42)

Unrealized (losses) gains on net investment hedges

(2) (3)

(97)

Cash flow hedges

Net derivative gains

(4)

Less: reclassification adjustment for gains included in income

(2)

(1)

Net effects of cash flow hedges

(2)

Unrealized losses on available-for-sale investment

(1)

Net change in unrecognized pension and post-retirement benefit obligation

(5)

124

Other comprehensive income

(6)

553

104

Comprehensive income

1,562

665

Comprehensive income attributable to non-controlling interest

Comprehensive Income of Emera Incorporated

1,561

664

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

1) Net of tax expense of $

million for the year ended December 31, 2022 (2021 – $

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 recovery of $

million for the year ended December 31, 2022 (2021 – $

million expense).

4) Net of tax recovery of $

million for the year ended December 31, 2022 (2021 – $

million expense).

5) Net of tax expense of $

million for the year ended December 31, 2022 (2021 – $

million expense).

6) Net of tax expense of $

million for the year ended December 31, 2022 (2021 – $

million expense).

Emera Incorporated

Consolidated Balance Sheets

As at

December 31

millions of dollars

2022

2021

Assets

Current assets

Cash and cash equivalents

310

394

Restricted cash (note 32)

Inventory (note 14)

769

538

Derivative instruments (notes 15 and 16)

296

195

Regulatory assets (note 7)

602

253

Receivables and other current assets (note 18)

2,897

1,733

4,896

3,136

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

net of accumulated depreciation

and amortization of $

9,574

and $

8,739

, respectively (note 20)

22,996

20,353

Other assets

Deferred income taxes (note 10)

237

295

Derivative instruments (notes 15 and 16)

100

106

Regulatory assets (note 7)

3,018

2,313

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

604

503

Investments subject to significant influence (note 8)

1,418

1,382

Goodwill (note 22)

6,012

5,696

Other long-term assets (note 32)

461

460

11,850

10,755

Total assets

39,742

34,244

Liabilities and Equity

Current liabilities

Short-term debt (note 23)

2,726

1,742

Current portion of long-term debt (note 25)

574

462

Accounts payable

2,025

1,485

Derivative instruments (notes 15 and 16)

888

533

Regulatory liabilities (notes 7 and 32)

495

290

Other current liabilities (note 24)

579

366

7,287

4,878

Long-term liabilities

Long-term debt (note 25)

15,744

14,196

Deferred income taxes (note 10)

2,196

1,868

Derivative instruments (notes 15 and 16)

190

149

Regulatory liabilities (note 7)

1,778

1,765

Pension and post-retirement liabilities (note 21)

281

370

Other long-term liabilities (notes 8 and 26)

825

868

21,014

19,216

Equity

Common stock (note 11)

7,762

7,242

Cumulative preferred stock (note 28)

1,422

Contributed surplus

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

578

Retained earnings

1,584

1,348

Total Emera Incorporated equity

11,427

10,116

Non-controlling interest in subsidiaries (note 29)

Total equity

11,441

10,150

Total liabilities and equity

39,742

34,244

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

Emera Incorporated

Consolidated Statements of Cash Flows

For the

Year ended December 31

millions of dollars

2022

2021

Operating activities

Net income

1,009

561

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

Depreciation and amortization

959

915

Income from equity investments, net of dividends

(61)

(69)

Allowance for equity funds used during construction

(52)

(61)

Deferred income taxes, net

152

(37)

Net change in pension and post-retirement liabilities

(48)

(23)

Fuel adjustment mechanism ("FAM")

(162)

(166)

Net change in fair value of derivative instruments

206

404

Net change in regulatory assets and liabilities

(471)

(176)

Net change in capitalized transportation capacity

(445)

(107)

Impairment charge

Other operating activities, net

(13)

Changes in non-cash working capital (note 30)

(234)

(152)

Net cash provided by operating activities

913

1,185

Investing activities

Additions to PP&E

(2,596)

(2,359)

Other investing activities

Net cash used in investing activities

(2,569)

(2,332)

Financing activities

Change in short-term debt, net

1,028

(155)

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

544

640

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

(680)

(377)

Proceeds from long-term debt, net of issuance costs

784

2,554

Retirement of long-term debt

(367)

(1,660)

Net proceeds under committed credit facilities

511

Issuance of common stock, net of issuance costs

277

317

Issuance of preferred stock, net of issuance costs (note 28)

416

Dividends on common stock

(472)

(443)

Dividends on preferred stock

(63)

(50)

Other financing activities

(7)

(13)

Net cash provided by financing activities

1,555

1,311

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

(1)

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

(85)

163

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

417

254

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

332

417

Cash, cash equivalents, and restricted cash consists of:

Cash

302

237

Short-term investments

157

Restricted cash

Cash, cash equivalents, and restricted cash

332

417

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

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

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, 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 at-the-market

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

issuance costs

248

Issued under the Dividend

Reinvestment Program ("DRIP"), net of

discount

238

Senior management stock options

exercised and Employee Share

Purchase Plan

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

Balance, December 31, 2020

6,705

1,004

(79)

1,495

9,238

Net income of Emera Inc.

560

561

Other comprehensive income, net of tax

expense of $

million

104

Issuance of preferred stock, net of after-

tax issuance costs

418

Dividends declared on preferred stock

(note 28)

(50)

Dividends declared on common stock

2.5750

/share)

(657)

Issued under the ATM, net of after-tax

issuance costs

284

Issued under the DRIP,

net of discount

215

Senior management stock options

exercised and Employee Share

Purchase Plan

Other

(1)

Balance, December 31, 2021

7,242

1,422

1,348

10,150

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

Emera Incorporated

Notes to the Consolidated Financial Statements

As at December 31, 2022 and 2021

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, 2022, Emera’s reportable segments include the following:

●

Florida Electric Utility, which consists of Tampa

Electric,

a vertically integrated regulated electric

utility, serving approximately

827,000

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

541,000

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, owned and constructed by Nalcor Energy.

ENL’s two investments are:

●

100

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

Maritime Link Project, a $

1.8

billion (including allowance for funds used during

construction (“AFUDC”)) transmission project; and

●

31.9

per cent investment 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 (“PGS”), a regulated gas distribution utility, serving approximately

468,000

customers across Florida;

●

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

serving

approximately

545,000

customers in New Mexico;

●

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

145

-kilometre pipeline

delivering re-gasified liquefied natural gas (“LNG”) from Saint John, New Brunswick to the

United States border under a

-year firm service agreement with Repsol Energy North

America Canada Partnership, which expires in 2034;

●

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

transmission company in Florida; and

●

12.9

per cent 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

133,000

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.

●

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

which includes:

●

Emera Energy, which consists of:

●

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

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

●

Brooklyn Power Corporation (“Brooklyn Energy”), a

MW biomass co-generation

electricity facility in Brooklyn, Nova Scotia; and

●

50.0

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

Swamp”), a

660

MW pumped storage hydroelectric facility in northwestern

Massachusetts.

●

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

financing subsidiaries of Emera;

●

Emera Technologies LLC, a wholly owned technology company focused on finding ways to

deliver renewables 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 entity that most significantly impacts its economic performance and the

obligation to absorb losses of the entity that could potentially be significant to the entity. 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.

Use of Management Estimates

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

to make estimates and assumptions. These may affect the 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. The rates are designed to recover prudently incurred costs of providing the regulated

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

applicable. For further detail, refer to note 7.

Foreign Currency Translation

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

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

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

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

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

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

and liabilities are deferred on the balance sheet in AOCI.

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

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

these investments, measured at the 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 regulator 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, the electricity and

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

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

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

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

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

Non-regulated Revenue:

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

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

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

basis, reflecting the nature of the 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.

Leases

The Company determines whether a contract contains a lease at inception by evaluating if 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 with annual requirements

to purchase wind and hydro energy over varying contract lengths that 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.

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 fair value 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.

Franchise Fees and Gross Receipts

Tampa

Electric 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 Tampa Electric 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.

Property, Plant and Equipment

PP&E are 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 “Property, plant

and equipment”. 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 the overall life of the

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

the underlying asset, the cost is capitalized.

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

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

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

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

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

Intangible assets, which are included in “Property, plant and equipment,” 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 fair

values 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. Under

the applicable accounting guidance, goodwill is subject to assessment for impairment at the reporting unit

level annually, or if an event or change in circumstances indicates that the fair value 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 the qualitative assessment and determines that it is more likely than not that its

fair value 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 fair value of the

reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit

exceeds its fair value, an impairment loss is recorded. Management estimates the fair value of the

reporting unit by using the income approach, or a combination of the income and market approach. The

income approach is applied using a discounted cash flow analysis which relies on management’s best

estimate of the reporting units’ 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. When using the market approach,

management estimates fair value based on comparable companies and transactions within the utility

industry. Significant assumptions used in estimating the fair value include discount and growth rates, rate

case assumptions including future cost of capital, valuation of the reporting units' net operating loss

(“NOL”) and projected operating and capital cash flows. Adverse changes in these assumptions could

result in a future material impairment of the goodwill assigned to Emera’s reporting units.

As of December 31, 2022, $

6,009

million of Emera’s goodwill represents the excess of the acquisition

purchase price for TECO Energy (Tampa Electric, PGS and NMGC reporting units) over the fair values

assigned to identifiable assets acquired and liabilities assumed. In Q4 2022, qualitative assessments

were performed for Tampa Electric and PGS given the significant excess of fair value over carrying

amounts calculated during the last quantitative test in Q4 2019. Management concluded it was more likely

than not that the fair value of these reporting units exceeded their respective carrying amounts, including

goodwill. As such, no quantitative testing was required. For the NMGC reporting unit, Emera elected to

bypass a qualitative assessment and performed a quantitative impairment assessment using a

combination of the income and market approach. This assessment estimated that the fair value of the

NMGC reporting unit exceeded its carrying amount, including goodwill. As a result of this assessment,

impairment charges were recognized.

In Q4 2022, the Company elected to bypass a qualitative assessment and performed a quantitative

impairment assessment for GBPC, using the income approach, as this reporting unit is sensitive to

changes in assumptions due to limited excess of fair value over the carrying value, including goodwill.

Although the cash flows of GBPC have not changed significantly compared to previous periods, it was

determined that the carrying amount, including goodwill, exceeded the fair value, due to an increase in

discount rates. The discount rate for the reporting unit was negatively impacted by changes in the macro-

economic environment, including the risk-free rate assumption. 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. No impairment was recorded in 2021. For further detail, refer to note 22.

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 the 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 tax assets will be recovered from future taxable

income is assessed and assumptions about the expected timing of the reversal of deferred tax assets and

liabilities are made. If management subsequently determines that it is likely that some or all of a deferred

income tax asset will not be realized, then 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 by Tampa

Electric, PGS and NMGC on regulated assets are deferred and amortized over the

estimated service lives of the related properties, as required by regulatory practices.

Tampa

Electric, 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 the regulator. 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,

foreign exchange, interest rates and share prices through contractual protections with counterparties

where practicable, and by using financial instruments consisting mainly of foreign exchange 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 held-for-trading (“HFT”). Collectively, these

contracts and financial instruments are considered derivatives.

The Company recognizes the fair value 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 where the criteria are no longer met.

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

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

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

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

effectiveness requirements are not met, the derivatives are recognized at fair value with any changes in

fair value recognized in net income in the reporting period, unless deferred as a result of regulatory

accounting.

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

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

change in fair value 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. Tampa Electric has no derivatives related

to hedging as a result of a FPSC approved five-year moratorium on hedging of natural gas purchases

which ends on December 31, 2022. Tampa Electric’s

moratorium on hedging of natural gas purchases

will continue through December 31, 2024, as a result of Tampa Electric’s 2021 rate case settlement

agreement.

Derivatives that do not meet any of the above criteria are designated as HFT, with changes in fair value

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 fuel for generation and purchased

power, other expenses, inventory,

OM&G and PP&E, 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 fair value 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”.

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 that 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 the 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 fair value. 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.

As at December 31, 2022, there are no indications of impairment of Emera’s long-lived assets.

impairment charges related to long-lived assets were recognized in 2022 or 2021.

Equity Method Investments:

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

comparing the fair value of these investments to their carrying values, if a fair value 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 fair value.

impairment of equity method investments was

required in either 2022 or 2021.

Financial Assets:

Equity investments, other than those accounted for under the equity method, are measured at fair value,

with changes in fair value recognized in the Consolidated Statements of Income. Equity investments that

do not have readily determinable fair values 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 2022 or 2021.

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 fair value of the 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 which are not

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

reasonably estimated, given there is 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 fair value in the period in which an amount can

be determined.

Cost of Removal

Tampa

Electric, PGS, NMGC and NSPI recognize non-ARO costs of removal (“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.

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 fair value-based method of accounting for stock-based compensation.

Stock-based compensation cost is measured at the grant date, based on the calculated fair value 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 fair value and re-measured at fair value 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 the unamortized gains

and losses and past service costs in AOCI or regulatory assets. 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.

CHANGE IN ACCOUNTING POLICY

The new USGAAP accounting policy that is applicable to, and adopted by the Company in 2022, is

described as follows:

Facilitation of the Effects of Reference Rate Reform on Financial Reporting

The Company adopted Accounting Standard Update (“ASU”) 2022-06,

Reference Rate Reform (Topic

848): Deferral of the Sunset Date of Topic 848

in Q4 2022. The update extends the period of time

preparers can utilize the reference rate reform relief guidance issued under ASU 2020-04, which was

adopted by the Company in Q4 2020. The guidance in ASU 2022-06 was effective as of the date of

issuance and entities may elect to apply the guidance prospectively through to December 31, 2024. The

Company has applied the guidance permitted by ASU 2020-04 to certain debt agreements that were

amended during the current period. The Company’s transition from reference rates will not have a

material impact on the consolidated financial statements.

FUTURE ACCOUNTING PRONOUNCEMENTS

The Company considers the applicability and impact of all ASUs issued by the Financial Accounting

Standards Board (“FASB”). ASUs issued by FASB, but which are not yet effective, were assessed and

determined to be either not applicable to the Company or to have an insignificant impact on the

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.

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, 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 (expense), net

145

Interest expense, net

(2)

185

136

288

709

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.

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, 2021

Operating revenues from

external customers

(1)

2,718

1,501

1,276

445

(175)

5,765

Inter-segment revenues

(1)

(28)

Total operating revenues

2,724

1,501

1,280

445

(157)

(28)

5,765

Regulated fuel for generation

and purchased power

894

654

218

(3)

1,763

Regulated cost of natural gas

472

OM&G

536

291

325

140

106

(30)

1,368

Provincial, state and municipal

taxes

212

330

Depreciation and amortization

469

246

121

902

Income from equity investments

103

143

Other income (expenses), net

(5)

Interest expense, net

(2)

138

132

256

611

Income tax expense (recovery)

(150)

(6)

Non-controlling interest in

subsidiaries

Preferred stock dividends

Net income (loss) attributable to

common shareholders

462

241

198

(412)

510

Capital expenditures

1,331

366

515

111

2,328

As at December 31, 2021

Total assets

17,903

7,418

6,666

1,402

2,034

(1,179)

34,244

Investments subject to

significant influence

1,215

123

1,382

Goodwill

4,436

1,189

5,696

(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 the 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, 2021, 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

2022

2021

United States

5,346

3,754

Canada

1,725

1,566

Barbados

384

292

The Bahamas

122

110

Dominica

7,588

5,765

Property Plant and Equipment:

As at

December 31

millions of dollars

2022

2021

United States

17,382

14,978

Canada

4,689

4,440

Barbados

583

535

The Bahamas

342

322

Dominica

22,996

20,353

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, 2022

Regulated Revenue

Residential

1,799

834

184

800

3,617

Commercial

869

427

282

461

2,039

Industrial

230

353

(7)

691

Other regulatory deferrals

371

411

Other (1)

283

(7)

335

Finance income (2)(3)

Regulated revenue

3,287

1,675

518

1,688

(14)

7,154

Non-Regulated Revenue

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

For the year ended December 31, 2021

Regulated Revenue

Residential

1,449

797

165

642

3,053

Commercial

754

407

232

379

1,772

Industrial

215

237

(2)

541

Other regulatory deferrals

289

323

Other (1)

122

(8)

179

Finance income (2)(3)

Regulated revenue

2,724

1,501

445

1,266

(10)

5,926

Non-Regulated

Marketing and trading margin (4)

102

Other non-regulated operating

revenue

(21)

Mark-to-market (3)

(289)

(286)

Non-regulated revenue

(157)

(18)

(161)

Total operating revenues

2,724

1,501

445

1,280

(157)

(28)

5,765

(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, 2022, the

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

450

million (2021 – $

437

million). This amount includes $

144

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

2042

7. REGULATORY

ASSETS AND LIABILITIES

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

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

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

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

management no longer considers it probable that an asset will be recovered, the 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

2022

2021

Regulatory assets

Deferred income tax regulatory assets

1,166

1,045

Cost recovery clauses

707

114

Tampa Electric capital cost recovery for early retired assets

674

657

Pension and post-retirement medical plan

369

291

FAM

307

145

Storm reserve

103

NMGC winter event gas cost recovery

117

Storm restoration

Deferrals related to derivative instruments

Environmental remediations

Stranded cost recovery

Other

106

3,620

2,566

Current

602

253

Long-term

3,018

2,313

Total regulatory assets

3,620

2,566

Regulatory liabilities

Accumulated reserve - cost of remova

895

819

Deferred income tax regulatory liabilities

877

863

Deferrals related to derivative instruments

230

241

NMGC gas hedge settlements (note 18)

162

Cost recovery clauses

Self-insurance fund (note 32)

Storm reserve

Other

2,273

2,055

Current

495

290

Long-term

1,778

1,765

Total regulatory liabilities

2,273

2,055

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.

Cost Recovery Clauses

These assets and liabilities are related to Tampa Electric, 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.

Tampa Electric 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 will be 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 Tampa Electric

section below.

Pension and Post-Retirement Medical Plan

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

Electric, 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.

FAM

This regulated asset is the difference between actual fuel costs and amounts recovered from NSPI

customers through electricity rates in a given year and deferred to a FAM regulatory asset or liability and

recovered from or returned to customers in subsequent periods. For the years 2020 through 2022,

differences between actual fuel costs and fuel revenues recovered from customers will be recovered from

customers in future periods. The Nova Scotia Utility and Review Board’s (“UARB”) decision to approve

the fuel stability plan directed that any annual non-fuel revenues above NSPI’s approved range of ROE

are to be applied to the FAM.

Storm Reserve

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

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

liability, the excess is to be carried as a regulatory asset. Tampa

Electric 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 September 2022, Tampa

Electric and PGS were impacted by Hurricane

Ian. For further information, refer to “Storm Reserve – Hurricane Ian” in both Tampa Electric and PGS

sections below.

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 April 16, 2021, NMGC filed a Motion for Extraordinary Relief, as permitted by the NMPRC

rules, to extend the terms of the repayment of the incremental gas costs and to recover a carrying charge.

On June 15, 2021, the NMPRC approved the recovery of $

108

million USD and related borrowing costs

over a period of 30 months beginning July 1, 2021.

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.

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

million USD

of costs related to Hurricane Dorian in 2019, over a

five-year

period. The recovery was implemented

through rates on January 1, 2021.

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.

Deferrals Related to Derivative Instruments

This asset is primarily related to NSPI deferring changes in fair value 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 its regulator. The realized gain or loss is recognized when the hedged item settles in

regulated fuel for generation and purchased power, inventory,

other income, OM&G or PP&E, depending

on the nature of the item being economically hedged.

Environmental Remediations

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

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

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

approved by the FPSC.

Stranded Cost Recovery

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

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

included in rates in future years.

Accumulated Reserve – Cost of Removal (“COR”)

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

AROs represent the fair value 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 the regulatory deferral of gas options exercised above strike price but

will settle in cash in Q1 2023. The value from the cash settlement of this options will flow through to

customers via the PGAC.

Regulatory Environments and Updates

Florida Electric Utility

Tampa Electric is regulated by the FPSC and is also subject to regulation by the Federal Energy

Regulatory Commission (“FERC”). The FPSC sets rates at a level that allows utilities such as Tampa

Electric 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 Tampa Electric, the FPSC or other interested parties.

Tampa

Electric’s approved regulated return on equity (“ROE”) range for 2022 and 2021 was

9.25

per cent

11.25

per cent based on an allowed equity capital structure of

per cent. An ROE of

10.20

per cent

(2021 -

10.25

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

Fuel Recovery and Other Cost Recovery Clauses:

Tampa

Electric 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 the 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, Tampa

Electric 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 proposed changes will be decided

by the FPSC in March 2023, and recovery is expected to begin in April 2023.

The mid-course fuel adjustment requested by Tampa Electric 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.

Base Rates:

On October 21, 2021, the FPSC approved a settlement agreement filed by Tampa Electric. The

settlement agreement allows for an increase to rates of $

191

million USD annually effective January

2022. This increase consisted of $

123

million USD in base rate charges and $

million USD to recover

the costs of retiring assets including, Big Bend coal generation assets Units 1 through 3 and meter

assets. The settlement agreement further includes two subsequent year adjustments of $

million USD

and $

million USD, effective January 2023 and January 2024, respectively related to the recovery of

future investments in the Big Bend Modernization project and solar generation. The allowed equity in the

capital structure will continue to be

per cent from investor sources of capital. The settlement

agreement includes an allowed regulated ROE range of

9.0

per cent to

11.0

per cent with a

9.95

per cent

midpoint. It also provides for a

basis point increase in the allowed ROE range and mid-point, and $

million USD of additional revenue, if United States Treasury Bond yields exceed a specific threshold set

on the date the FPSC approved the agreement. Under the agreement base rates are frozen from January

1, 2022 to December 31, 2024, unless Tampa Electric’s

earned ROE were to fall below the bottom of the

range during that time. The settlement agreement provides for the deferral of income taxes as a result of

changes in tax laws. The changes would be reflected as a regulatory asset or liability and either result in

an increase or a decrease in customer rates through a subsequent regulatory process. The settlement

agreement further creates a mechanism to recover the costs of retiring coal generation units and meter

assets over a period of

15 years

which survives the term of that agreement. The settlement agreement

sets new depreciation and dismantlement rates effective January 1, 2022 and contains the provisions that

Tampa

Electric will not have to file another depreciation study during the term of the agreement but will

file a new depreciation study no more than

one year

, nor less than

90 days

, before the filing of its next

general base rate proceeding. Tampa Electric agreed not to hedge natural gas through the period ending

on December 31, 2024.

On August 16, 2022, the FPSC approved Tampa Electric’s

request to increase revenue and ROE due to

increases in the 30-year United States Treasury bond yield rate. Effective July 1, 2022, the new mid-point

ROE is

10.20

per cent, and the range is

9.25

per cent to

11.25

per cent.

Storm Reserve – Hurricane Ian:

In September 2022, Tampa

Electric was impacted by Hurricane Ian. Total restoration costs were $

126

million USD, with $

119

million USD of restoration costs charged against Tampa Electric’s FPSC approved

storm reserve. Total restoration costs charged to the storm reserve have exceeded the reserve balance

and have been deferred as a regulatory asset for future recovery. On January 23, 2023, Tampa

Electric

petitioned the FPSC for recovery of the storm reserve regulatory asset and the replenishment of the

balance in the reserve to the previous approved reserve level of $

million USD, for a total of

approximately $

131

million USD. The proposed changes will be decided by the FPSC in March 2023 and

recovery is expected to begin in April 2023 through March 2024.

Solar Base Rate Adjustments Included in Base Rates:

During 2017 to 2021, Tampa

Electric invested $

850

million USD in

600

MW of utility-scale solar

photovoltaic projects, which is recoverable through FPSC-approved solar base rate adjustments

(“SoBRAs”). AFUDC was earned on these projects during construction. The FPSC has approved SoBRAs

representing a total of

600

MW or $

104

million USD annually in estimated revenue requirements for in-

service projects.

On October 12, 2021, the FPSC approved the true-up filing for SoBRA tranche 3, included in base rates

as of January 2020. A $

million USD true-up was returned to customers during 2021. No true-up for

SoBRA tranche 4 was required.

Storm Protection Cost Recovery Clause and Settlement Agreement:

On October 3, 2019, the FPSC issued a rule to implement a Storm Protection Plan (“SPP”) Cost

Recovery Clause. This clause provides a process for Florida investor-owned utilities, including Tampa

Electric, 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 Tampa

Electric’s cost recovery began in January 2021. The current approved plan addressed the

years 2020 through 2022, and in April 2022 Tampa Electric submitted a new plan to determine cost

recovery in 2023, 2024 and 2025. On October 4, 2022, the FPSC approved Tampa Electric’s SPP.

Big Bend Modernization Project:

Tampa

Electric invested $

876

million USD, including $

million USD of AFUDC, during 2018 through

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, Tampa Electric retired the Unit 1 components that will not be used in the

modernized plant in 2020 and Big Bend Unit 2 in 2021. Tampa Electric plans to retire Big Bend Unit 3 in

2023 as it is in the best interest of the customers from an economic, environmental risk and operational

perspective.

At December 31, 2021, the balance sheet included $

636

million USD in electric utility plant and $

267

million USD in accumulated depreciation related to Unit 1 components and Unit 2 and Unit 3 assets. In

accordance with Tampa Electric’s

2017 settlement agreement approved by the FPSC, Tampa Electric

continued to account for its existing investment in Unit 1, 2 and 3 in electric utility plant and depreciated

the assets using the current depreciation rates until December 31, 2021, at which point they were

reclassified to a regulatory asset on the balance sheet.

Tampa

Electric’s 2021 settlement agreement provides recovery for 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 will be recovered as part of the 2023

subsequent year adjustment. The settlement agreement also includes a new charge to recover the

remaining costs of the retiring Big Bend coal generation assets, Units 1 through 3, which will be spread

over

15 years

and will survive the termination of the settlement agreement. The special capital recovery

schedule for all three units was applied beginning January 1, 2022. This recovery mechanism is

authorized by and survives the term of the settlement agreement approved by the FPSC in 2021.

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 2022 and 2021 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.

NSPI has a FAM, approved by the UARB, allowing NSPI to recover fluctuating fuel 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.

For the period of 2020 through 2022, NSPI operated under a

three-year

fuel stability plan which resulted

in an average annual overall rate increase of

1.5

per cent to recover fuel costs. These rates included

recovery of Maritime Link costs.

General Rate Application (“GRA”):

On November 9, 2022, the Nova Scotia provincial government enacted Bill 212, “Public Utilities Act

(amended)”. The legislation limits non-fuel rate increases in NSPI’s 2022 GRA to the UARB, excluding

increases relating to demand side management (“DSM”) costs, to a total of

1.8

per cent between the

effective date of the UARB’s decision and the end of 2024. The legislation also:

●

requires revenue generated from the non-fuel rate increase to be used only to improve the

reliability of service to ratepayers,

●

limits NSPI’s return on equity to

9.25

per cent and equity ratio to

per cent, and

●

limits the rate used to accrue interest on regulatory deferrals to the Bank of Canada policy

interest rate plus

1.75

per cent, unless otherwise directed by the UARB.

On November 24, 2022, NSPI filed with the UARB a comprehensive settlement agreement between

NSPI, key customer representatives and participating interest groups (“NSPI Settlement Agreement”) in

relation to its GRA filed in January 2022. The NSPI Settlement Agreement was structured to be

consistent with the amendments to the Public Utilities Act made under Bill 212, including the

1.8

per cent

cap on non-fuel rate increases for 2023 and 2024. The NSPI Settlement Agreement also addresses the

recovery of fuel costs over the settlement period and establishes a DSM rider. This will result in a

combined fuel and non-fuel rate increase of

6.9

per cent each year for 2023 and 2024, and annualised

incremental revenue (fuel and non-fuel) of $

105

million in 2023 and $

115

million in 2024. In addition, any

under or over recovery of fuel costs will be addressed through the UARB’s established FAM process.

NSPI’s ROE range will continue to be

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. The NSPI Settlement Agreement also

establishes a 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 expense exceeds approximately $

million in a

given year. On February 2, 2023, NSPI received the UARB’s decision, which substantially approved the

Settlement Agreement as filed. Approved rate increases will be effective as of the date of the decision.

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.

As part of a

three-year

fuel stability plan, electricity rates were set to include amounts of $

164

million and

162

million for 2021 and 2022, respectively. Any difference between the amounts included in the fuel

stability plan 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 at December 31, 2022, the FAM includes a recovery of $

172

million (December 31, 2021 – $

million) non-cash accrual representing the estimated future cost of acquiring emissions credits for the

2019 through 2022 Cap-and-Trade compliance period. Emissions for the compliance period will not be

finalized until the completion of the environmental audit which begins in March 2023. Emissions are

currently based upon audited actual emissions from 2019 through 2021 and unaudited actuals for 2022.

The total cost of compliance with the Cap-and-Trade program compliance period could change

depending on the price paid for both credits at remaining provincial auctions and reserve credits

purchased from the provincial government, and the results of the 2022 environmental emissions audit.

Lower than forecast Muskrat Falls energy received during the compliance period has resulted in the

increased deployment of higher carbon-emitting generation sources. The Province of Nova Scotia has

agreed to provide approximately $

165

million of relief from the 2019 through 2022 compliance costs,

which was equal to the total cost of compliance forecast at the time of the fuel update submitted by NSPI

to the UARB in September 2022 as part of the GRA. Discussions related to the final amount of relief and

how this relief will be provided are ongoing. Further, NSPI’s regulatory framework provides for the

recovery of costs prudently incurred to comply with the Cap-and-Trade Program Regulations pursuant to

NSPI’s FAM.

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. NSPML also received approval to collect up to $

168

million (2021 – $

172

million) from NSPI for the recovery of costs associated with the Maritime Link in

2022. This was subject to a holdback of up to $

million a month, beginning April 2022, contingent on

receiving at least

per cent of NS Block deliveries, including Supplemental Energy deliveries.

In December 2022, NSPML received UARB approval to collect up to $

164

million from NSPI for the

recovery of costs associated with the Maritime Link in 2023. This continues to be subject to a holdback of

up to $

million a month, as discussed above. On December 22, 2022, the UARB clarified its earlier

direction regarding the holdback and NSPI can now release the holdback to NSPML when

per cent of

NS Block deliveries, including Supplemental Energy deliveries, is achieved. This enabled NSPI to pay

NSPML approximately $

million of the 2022 holdback. As of December 31, 2022, an additional $

million in aggregate has been held-back by NSPI. Determination of the allocation of the $

million

between NSPML and NSPI will be subject to a regulatory process that is expected to commence in early

2023 to review the holdback mechanism.

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 2022 and 2021 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.

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.

Storm Reserve – Hurricane Ian:

In September 2022, Hurricane Ian impacted PGS’s operations in Fort Myers and Sarasota. The

restoration costs were approximately $

million USD and $

million was charged against PGS’s FPSC-

approved storm reserve.

Base Rates:

On November 19, 2020, the FPSC approved a settlement agreement filed by PGS.

The settlement

agreement allows for an increase to base rates by $

million USD annually, effective January 1 2021,

which is a $

million USD increase in revenue and $

million USD increase of revenues previously

recovered through the cast iron and bare steel replacement rider. It provides PGS the ability to reverse a

total of $

million USD of accumulated depreciation through 2023. During 2022, PGS reversed $

million USD of the $

million USD accumulated depreciation. No amounts were reversed prior to 2022.

In addition, the agreement sets new depreciation rates effective January 1, 2021. Under the agreement

base rates are frozen from January 1, 2021 to December 31, 2023, unless its earned ROE were to fall

below

8.9

per cent before that time with an allowed equity in the capital structure of

54.7

per cent from

investor sources of capital. The settlement agreement provides for the deferral of income taxes as a

result of changes in tax laws. The changes would be reflected as a regulatory asset or liability and either

result in an increase or a decrease in customer rates through a subsequent regulatory process.

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 2022 and 2021 was

9.375

per cent on an allowed equity capital structure of

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

the 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. In December 2020, NMGC received

approval of its PGAC Continuation Filing for the four-year period ending December 2024.

Base Rates:

On December 13, 2021, NMGC filed a rate case with the NMPRC for new rates to become effective

January 2023. On May 20, 2022, NMGC filed an unopposed settlement agreement with the NMPRC for

an increase of $

million USD in annual base revenues. The rates reflect the recovery of increased

operating costs and capital investments in pipelines and related infrastructure. The NMPRC approved the

settlement agreement on November 30, 2022.

Weather Normalization Mechanism:

In July 2019, the NMPRC approved changes to the company’s rate design to include a five-year pilot of

Weather Normalization Mechanism. This clause is designed to lower the variability of weather impacts

during the October through April heating seasons. The Weather Normalization Mechanism allows

customer rates and company revenue to be more predictable by partially removing the impact of warmer

than usual or colder than usual weather. Weather-related revenue increases or decreases experienced

from October to April are adjusted annually in October of the following heating season.

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.

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”), an independent regulator, 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 2022 and 2021.

Licenses:

The Government of Barbados has granted BLPC a franchise to generate, transmit and distribute

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

number of licenses required for the supply of electricity from a single integrated license which currently

exists to multiple licenses for Generation, Transmission and Distribution, Storage, Dispatch and Sales. In

March 2021, BLPC reached commercial agreement with the Government of Barbados for each of the

license types, subject to the passage of implementing legislation. The new licenses are expected to take

effect in 2023 on completion of the legislative process. The Dispatch license will have a term of

5 years

with the remaining licenses having terms ranging from

30 years

. BLPC anticipates that any increased

costs associated with the implementation of the new multi-licensed structure will be recoverable through

BLPC’s regulatory framework. BLPC is awaiting final enactment and will work towards implementation of

the licenses once received.

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.

On October 4, 2021 BLPC submitted a general rate review application to the FTC. The application seeks

a rate adjustment and the implementation of a cost reflective rate structure that will facilitate the changes

expected in the newly reformed electricity market and the country’s transition towards 100 per cent

renewable energy generation. The application seeks recovery of capital investment in plant, equipment

and related infrastructure and results in an increase in annual non-fuel revenue of approximately $

million USD upon approval. The application includes a request for allowed regulatory ROE of

12.50

per

cent on an allowed equity capital structure of

per cent. On September 16, 2022, the FTC granted

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

million USD for the

remainder of 2022 and approximately $

million USD per month for 2023. Interim rate relief is effective

from September 16, 2022 until the implementation of final rates. The hearing concluded in October 2022.

On February 15, 2023, the FTC issued a decision on the BLPC rate review 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 of approximately $

million USD related to the self-insurance fund,

accumulated depreciation, and taxes. The impacts to BLPC's rate base and final rates are not yet

determinable. BLPC will seek to clarify aspects of the FTC decision in its compliance filing and is also

considering filing a submission to the FTC for a review of the decision. BLPC expects a decision on final

rates from the FTC in 2023.

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. A decision is expected from the FTC in 2023.

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

8.23

per cent for 2022 (2021 –

8.37

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 will be adjusted

monthly, in-line with actual fuel costs.

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 new rates include a regulatory ROE of

12.84

per

cent.

Storm Restoration Costs – Hurricane Matthew:

In 2017, as part of the recovery of costs incurred as a result of Hurricane Matthew, 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.

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

2022

2021

2022

2021

2022

LIL

(1)

740

682

31.9

NSPML

501

533

100.0

M&NP

(2)

128

123

12.9

Lucelec

(2)

19.5

Bear Swamp

(3)

50.0

1,418

1,382

129

143

(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) Although Emera’s ownership percentage of these entities is relatively low,

it is considered to have significant influence over the

operating and financial decisions of these companies through Board representation. Therefore, Emera records its investment

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 (2021 – $

104

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 fair value 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

2022

2021

Balance Sheets

Current assets

PP&E

1,517

1,587

Regulatory assets

265

247

Non-current assets

Total assets

1,828

1,890

Current liabilities

Long-term debt

(1)

1,149

1,189

Non-current liabilities

130

118

Equity

501

533

Total liabilities and equity

1,828

1,890

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

OTHER INCOME, NET

For the

Year ended December 31

millions of dollars

2022

2021

TECO Guatemala Holdings award

(1)

AFUDC

Other

145

(1) Refer to note 27 for further detail related to the TECO Guatemala Holdings award.

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

2022

2021

Income before provision for income taxes

1,194

555

Statutory income tax rate

29.0%

Income taxes, at statutory income tax rate

346

161

Deferred income taxes on regulated income recorded as regulatory assets and

regulatory liabilities

(70)

(62)

Foreign tax rate variance

(44)

(42)

Amortization of deferred income tax regulatory liabilities

(33)

GBPC impairment charge

Tax effect

of equity earnings

(10)

(16)

Tax credits

(18)

(13)

Other

(7)

(1)

Income tax expense (recovery)

185

(6)

Effective income tax rate

15%

(1%)

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. During 2022, the Company

recorded a $

million regulatory liability 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

2022

2021

Current income taxes

Canada

United States

Deferred income taxes

Canada

120

(33)

United States

252

118

Other

Investment tax credits

United States

(7)

(11)

Operating loss carryforwards

Canada

(92)

(64)

United States

(121)

(49)

Income tax expense (recovery)

185

(6)

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

2022

2021

Canada

173

244

United States

1,063

289

Other

(42)

Income before provision for income taxes

1,194

555

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

December 31 consisted of the following:

millions of dollars

2022

2021

Deferred income tax assets:

Tax loss carryforwards

1,207

873

Tax credit carryforwards

415

375

Regulatory liabilities - cost of removal

177

170

Derivative instruments

188

Other

428

434

Total deferred income tax assets before valuation allowance

2,272

2,040

Valuation allowance

(312)

(256)

Total deferred income tax assets after valuation allowance

1,960

1,784

Deferred income tax (liabilities):

PP&E

(2,981)

(2,622)

Regulatory assets

(219)

(78)

Derivative instruments

(125)

(197)

Other

(594)

(460)

Total deferred income tax liabilities

(3,919)

(3,357)

Consolidated Balance Sheets presentation:

Long-term deferred income tax assets

237

295

Long-term deferred income tax liabilities

(2,196)

(1,868)

Net deferred income tax liabilities

(1,959)

(1,573)

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 $

312

million has been recorded as at December 31, 2022 (2021 – $

256

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, 2022, $

3.8

billion (2021 – $

2.9

billion) in cumulative temporary differences for which

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

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

occurred.

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

2022 consisted of the following:

Subject to

Tax

Valuation

Net Tax

Expiration

millions of dollars

Carryforwards

Allowance

Carryforwards

Period

Canada

NOL

2,372

(977)

1,395

2026 - 2042

Capital loss

(79)

Indefinite

United States

Federal NOL

2,082

2032 - Indefinite

State NOL

1,489

2032 - Indefinite

Tax credit

415

2025 - 2042

Other

NOL

(33)

2023 - 2029

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

December 31 as follows:

millions of dollars

2022

2021

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)

(1)

Decreases due to settlement with tax authorities

(6)

Balance, December 31

The total amount of unrecognized tax benefits as at December 31, 2022 was $

million (2021 - $

million), which would affect the effective tax rate if recognized. The total amount of accrued interest with

respect to unrecognized tax benefits was $

million (2021 – $

million) with $

million interest expense

recognized in the Consolidated Statements of Income (2021 –

nil

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 (2021 – $

million), including interest. NSPI has prepaid $

million (2021

– $

million) of the amount in dispute, as required by CRA.

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

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

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

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

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

available in subsequent years.

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

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

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

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

determinable at this time.

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

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

2022, 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.

2022

2021

Issued and outstanding:

millions

of shares

millions of

dollars

millions of

dollars

Balance, December 31, 2021

261.07

7,242

251.43

6,705

Issuance of common stock under ATM program

(1)(2)

4.07

248

4.99

284

Issued under the DRIP,

net of discounts

4.21

238

3.90

215

Senior management stock options exercised and Employee Share

Purchase Plan

0.60

0.75

Balance, December 31, 2022

269.95

7,762

261.07

7,242

(1) As at December 31, 2021, a total of

4,987,123

common shares were issued under Emera's ATM

program at an average price of

57.63

per share for gross proceeds of $

287

million ($

284

million net of after-tax issuance costs).

(2) For the year ended December 31, 2022,

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).

On August 12, 2021, Emera renewed its ATM Program that allows the Company to issue up to $

600

million of common shares from treasury to the public from time to time, at the Company's discretion, at

the prevailing market price. The ATM Program was renewed pursuant to a prospectus supplement to the

Company's short form base shelf prospectus dated August 5, 2021. The ATM program is expected to

remain in effect until September 5, 2023. As at December 31, 2022, an aggregate gross sales limit of

207

million remains available for issuance under the ATM program.

As at December 31, 2022, the following common shares were reserved for issuance:

million (2021 –

6.2

million) under the senior management stock option plan,

2.7

million (2021 –

3.1

million) under the

employee common share purchase plan and

million (2021 –

14.2

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, 2022,

Emera is in compliance with this requirement.

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.

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)

2022

2021

Numerator

Net income attributable to common shareholders

945.1

510.5

Diluted numerator

945.1

510.5

Denominator

Weighted average shares of common stock outstanding

265.5

255.9

Weighted average deferred share units outstanding

(1)

1.3

Weighted average shares of common stock outstanding – basic

265.5

257.2

Stock-based compensation

0.4

Weighted average shares of common stock outstanding – diluted

265.9

257.6

Earnings per common share

Basic

3.56

1.98

Diluted

3.55

1.98

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

therefore no longer included

in the calculation of earnings per common share.

13.

ACCUMULATED OTHER COMPREHENSIVE INCOME

The components of AOCI are as follows:

millions of dollars

Unrealized gain

(loss) on

translation of

self-sustaining

foreign

operations

Net change in

net investment

hedges

Gains 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, 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

For the year ended December 31, 2021

Balance, January 1, 2021

(1)

(161)

(79)

Other comprehensive (loss)

income before

reclassifications

(42)

(19)

Amounts reclassified from

AOCI

(1)

124

123

Net current period other

comprehensive income (loss)

(42)

124

104

Balance, December 31, 2021

(1)

(37)

The reclassifications out of accumulated other comprehensive income (loss) are as follows:

For the

Year ended December 31

millions of dollars

2022

2021

Affected line item in the Consolidated Financial Statements

Gains on derivatives recognized as cash flow hedges

Interest rate hedge

Interest expense, net

(2)

(1)

Net change in unrecognized pension and post-retirement benefit costs

Actuarial losses

Other income, net

Amounts reclassified into obligations

Pension and post-retirement benefits

102

Total before tax

126

Income tax expense

(1)

(2)

Total net of tax

124

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

123

14.

INVENTORY

As at

December 31

millions of dollars

2022

2021

Fuel

404

255

Materials

365

283

Total

769

538

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

2022

2021

2022

2021

Regulatory deferral:

Commodity swaps and forwards

186

146

FX forwards

Physical natural gas purchases and sales

256

241

HFT derivatives:

Power swaps and physical contracts

Natural gas swaps, futures, forwards, physical

contracts

340

208

1,224

818

429

241

1,301

850

Other derivatives:

Equity derivatives

FX forwards

Total gross current derivatives

690

493

1,372

874

Impact of master netting agreements:

Regulatory deferral

(18)

(4)

(18)

(4)

HFT derivatives

(276)

(188)

(276)

(188)

Total impact of master netting agreements

(294)

(192)

(294)

(192)

Total derivatives

396

301

1,078

682

Current

(1)

296

195

888

533

Long-term

(1)

100

106

190

149

Total derivatives

396

301

1,078

682

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

Cash Flow Hedges

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

million that is being amortized through

interest expense over

10 years

as the underlying hedged item settles. As of December 31, 2022, the

unrealized gain in AOCI was $

million, net of tax (2021 – $

million, net of tax). For the year ended

December 31, 2022, unrealized gains of $

million (2021 – $

million) have been reclassified from AOCI

into interest expense. The Company expects $

million of unrealized gains currently in AOCI to be

reclassified into net income within the next twelve months

Regulatory Deferral

The Company has recorded the following changes in realized and unrealized gains (losses) 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

2022

2021

Unrealized gain (loss) in regulatory

assets

(69)

(7)

Unrealized gain (loss) in regulatory

liabilities

343

218

(3)

Realized loss in regulatory assets

Realized gain in regulatory liabilities

(41)

(3)

Realized (gain) loss in inventory

(1)

(121)

(8)

Realized (gain) loss in regulated fuel

for generation and purchased power

(2)

(64)

(146)

(39)

Total change in derivative instruments

(36)

161

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

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

terminated or the hedged transaction is no longer probable.

As at December 31, 2022, the Company had the following notional volumes designated for regulatory

deferral that are expected to settle as outlined below:

millions

2023

2024-2026

Physical natural gas purchases:

Natural gas (Mmbtu)

Commodity swaps and forwards purchases:

Natural gas (Mmbtu)

Power (MWh)

FX swaps and forwards:

FX contracts (millions of USD)

206

123

Weighted average rate

1.2832

1.3064

% of USD requirements

50%

28%

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

2022

2021

Power swaps and physical contracts in non-regulated operating revenues

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

operating revenues

(142)

Total gains (losses) in net income

(138)

As at December 31, 2022, the Company had the following notional volumes of outstanding HFT

derivatives that are expected to settle as outlined below:

2027 and

millions

2023

2024

2025

2026

thereafter

Natural gas purchases (Mmbtu)

319

131

Natural gas sales (Mmbtu)

492

205

105

Power purchases (MWh)

Power sales (MWh)

Other Derivatives

As at December 31, 2022, 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

2.8

million shares and extends until December 2023. The FX forwards have a

combined notional amount of $

448

million USD and expire throughout 2023, 2024, and 2025.

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

derivatives:

For the

Year ended December 31

millions of dollars

2022

2021

Equity

Forwards

Derivatives

Forwards

Derivatives

Unrealized gain (loss) in OM&G

(5)

Unrealized loss in other income, net

(18)

(15)

Realized gain (loss) in OM&G

(17)

Realized gain (loss) in other income, net

(6)

Total gains (losses) in net income

(24)

(22)

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, 2022, the maximum exposure the Company had to credit risk was $

1.9

billion (2021

– $

1.3

billion), which includes 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, 2022 was $

386

million (2021 – $

341

million), which

mitigates 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, 2022, the Company had $

131

million (2021 – $

114

million) in financial assets,

considered to be past due, which have been outstanding for an average

days. The fair value of these

financial assets is $

114

million (2021 – $

million), the difference of which is included in the allowance

for credit losses. These assets primarily relate to accounts receivable from electric and gas revenue.

Concentration Risk

The Company's concentrations of risk consisted of the following:

As at

December 31, 2022

December 31, 2021

millions of

dollars

% of total

exposure

millions of

dollars

% of total

exposure

Receivables, net

Regulated utilities:

Residential

455

19%

384

24%

Commercial

192

167

10%

Industrial

121

Other

122

890

37%

696

43%

Trading group:

Credit rating of A- or above

125

Credit rating of BBB- to BBB+

107

Not rated

307

13%

132

507

21%

305

19%

Other accounts receivable

585

25%

329

20%

1,982

83%

1,330

82%

Derivative Instruments

(current and long-term)

Credit rating of A- or above

202

155

Credit rating of BBB- to BBB+

Not rated

186

124

396

17%

301

18%

2,378

100%

1,631

100%

Cash Collateral

The Company’s cash collateral positions consisted of the following:

As at

December 31

millions of dollars

2022

2021

Cash collateral provided to others

224

212

Cash collateral received from others

112

100

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, 2022, the total fair value of derivatives in a liability position was $

1,078

million

(December 31, 2021

–

682

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.

16.

FAIR VALUE

MEASUREMENTS

The Company is required to determine the fair value 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 fair value

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 fair value measurement.

The following tables set out the classification of the methodology used by the Company to fair value its

derivatives

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

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)

As at

December 31, 2021

millions of dollars

Level 1

Level 2

Level 3

Total

Assets

Regulatory deferral:

Commodity swaps and forwards

101

142

FX forwards

Physical natural gas purchases and sales

101

237

HFT derivatives:

Power swaps and physical contracts

Natural gas swaps, futures, forwards, physical

contracts and related transportation

(1)

Other derivatives:

Equity derivatives

Total assets

115

104

301

Liabilities

Regulatory deferral:

Commodity swaps and forwards

FX forwards

HFT derivatives:

Power swaps and physical contracts

Natural gas swaps, futures, forwards and physical

contracts

122

515

650

127

518

662

Total liabilities

140

518

682

Net assets (liabilities)

(58)

(414)

(381)

The change in the fair value of the Level 3 financial assets for the year ended December 31, 2022 was as

follows:

Regulatory Deferral

HFT Derivatives

Physical natural

Natural

millions of dollars

gas purchases

Power

gas

Total

Balance, January 1, 2022

104

Realized gains included in fuel for generation and

purchased power

(64)

Unrealized gains included in regulatory liabilities

Total realized and unrealized gains included in non-

regulated operating revenues

Balance, December 31, 2022

The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2022 was

as follows:

HFT Derivatives

Natural

millions of dollars

Power

gas

Total

Balance, January 1, 2022

515

518

Total realized and unrealized gains (losses) included

in non-regulated operating revenues

(2)

310

308

Balance, December 31, 2022

825

826

Significant unobservable inputs used in the fair value 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) fair

value 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 fair value of Level 3

derivative instruments. The following table outlines quantitative information about the significant

unobservable inputs used in the fair value measurements categorized within Level 3 of the fair value

hierarchy:

December 31, 2022

As at

Significant

Weighted

millions of dollars

Fair Value

Unobservable Input

Low

High

average

(1)

Assets

Liabilities

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 fair value of the instruments.

December 31, 2021

As at

Significant

Weighted

millions of dollars

Fair Value

Unobservable Input

Low

High

average

(1)

Assets

Liabilities

Regulatory deferral –

Physical

Third-party pricing

$4.51

$26.09

$9.74

natural gas purchases

HFT derivatives – Power

Third-party pricing

$37.05

$213.00

$99.34

swaps and physical contracts

HFT derivatives – Natural

515

Third-party pricing

$1.90

$21.53

$8.80

gas swaps, futures, forwards

and physical contracts

Total

104

518

Net liability

414

(1) Unobservable inputs were weighted by the relative fair value of the instruments.

Long-term debt is a financial liability not measured at fair value on the Consolidated Balance Sheets. The

balance consisted of the following:

As at

Carrying

millions of dollars

Amount

Fair Value

Level 1

Level 2

Level 3

Total

December 31, 2022

16,318

14,670

14,284

386

14,670

December 31, 2021

14,658

16,775

16,308

467

16,775

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, 2022, the fair value of the Hybrid

Notes was $

1.1

billion (2021 – $

1.7

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

million was recorded

in AOCI for the year ended December 31, 2022 (2021 – $

million after-tax gain).

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 $

157

million for the year ended December 31, 2022 (2021 – $

149

million).

NSPML is accounted for as an equity investment and therefore, the 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, 2022 (2021

– $

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, 2022 and at December 31, 2021.

18.

RECEIVABLES AND OTHER CURRENT ASSETS

As at

December 31

millions of dollars

2022

2021

Customer accounts receivable – billed

1,096

767

Customer accounts receivable – unbilled

424

318

Allowance for credit losses

(17)

(21)

Capitalized transportation capacity

(1)

781

316

NMGC gas hedge settlement receivable

(2)

162

Income tax receivable

Prepaid expenses

Other

360

280

Total receivables and other current assets

2,897

1,733

(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) Related amount is included in regulatory liabilities for NMGC as gas hedges are part of the PGAC. Refer to note 7.

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 63 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 that they will be exercised.

As at

December 31

millions of dollars

Classification

2022

2021

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 has recorded lease expense of $

138

million for the year ended December 31, 2022 (2021

– $

150

million), of which $

131

million (2021 – $

142

million) relates 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

2023

2024

2025

2026

2027

Thereafter

Total

Minimum lease payments

116

139

Less imputed interest

(77)

Total

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

Year ended December 31

For the

2022

2021

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

3.98%

Lessor

The Company’s net investment in direct finance and sales-type leases primarily relates to Brunswick

Pipeline, Seacoast, compressed natural gas (“CNG”) stations 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 January 2022, the Company leased a 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 new 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.

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

2022

2021

Total minimum lease payment to be received

1,393

947

Less: amounts representing estimated executory costs

(205)

(165)

Minimum lease payments receivable

1,188

782

Estimated residual value of leased property (unguaranteed)

183

Less: unearned finance lease income

(733)

(443)

Net investment in direct finance and sales-type leases

638

522

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

current assets")

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

604

503

As at December 31, 2022, future minimum lease payments to be received for each of the next five years

and in aggregate thereafter are as follows:

millions of dollars

2023

2024

2025

2026

2027

Thereafter

Total

Minimum lease payments to be

received

930

1,393

Less: executory costs

(205)

Total

1,188

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

2022

2021

Generation

131

13,083

11,173

Transmission

2,731

2,532

Distribution

6,978

6,305

Gas transmission and distribution

5,061

4,385

General plant and other

(1)

2,723

2,473

Total cost

30,576

26,868

Less: Accumulated depreciation

(1)

(9,574)

(8,739)

21,002

18,129

Construction work in progress

(1)

1,994

2,224

Net book value

22,996

20,353

(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, 2022, SeaCoast’s share of plant in service was $

million USD (2021 - $

million USD), and

accumulated depreciation of $

million USD (2021 - $

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 and defined-contribution 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.

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

2022

2021

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

2,624

318

2,759

339

Service cost

Plan participant contributions

Interest cost

Benefits paid

(174)

(31)

(160)

(27)

Actuarial gains

(480)

(79)

(89)

(10)

Settlements and curtailments

(6)

Foreign currency translation adjustment

(2)

(1)

Balance, December 31

2,158

243

2,624

318

Change in plan assets

Balance, January 1

2,702

2,605

Employer contributions

Plan participant contributions

Benefits paid

(174)

(31)

(160)

(27)

Actual return on assets, net of expenses

(489)

(7)

214

Settlements and curtailments

(6)

Foreign currency translation adjustment

(5)

(1)

Balance, December 31

2,163

2,702

Funded status, end of year

(197)

(267)

The actuarial gains recognized in the period are primarily due to changes in the discount rate and

compensation-related assumption changes. This was partially offset by losses associated with member

experience and indexation.

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) exceeds the plan assets for the years ended December 31 is as follows:

millions of dollars

2022

2021

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

PBO/APBO

1,006

221

140

290

Fair value of plan assets

914

Funded status

(92)

(221)

(105)

(290)

Plans with Accumulated Benefit Obligation (“ABO”)

in Excess of Plan Assets

The ABO for the defined benefit pension plans was $

2,080

million as at December 31, 2022 (2021 –

2,507

million). The aggregate financial position for those plans with an ABO in excess of the plan assets

for the years ended December 31 is as follows:

millions of dollars

2022

2021

Defined benefit

pension plans

Defined benefit

pension plans

ABO

111

133

Fair value of plan assets

Funded status

(78)

(98)

Balance Sheet

The amounts recognized in the Consolidated Balance Sheets consisted of the following:

As at

December 31

millions of dollars

2022

2021

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Other current liabilities

(13)

(20)

(7)

(20)

Long-term liabilities

(80)

(201)

(100)

(270)

Other long-term assets

185

AOCI, net of tax and regulatory assets

358

230

Less: Deferred income tax (expense)

recovery in AOCI

(7)

(1)

(8)

Net amount recognized

356

(176)

300

(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

millions of dollars

Defined Benefit Pension Plans

Balance, January 1, 2022

192

Amortized in current period

(21)

(10)

Current year addition to AOCI or regulatory assets

147

(5)

Change in FX rate

Balance, December 31, 2022

336

Non-pension benefits plans

Balance, January 1, 2022

Amortized in current period

(2)

Current year addition to AOCI or regulatory assets

(62)

(10)

Change in FX rate

Balance, December 31, 2022

(10)

As at

December

millions of dollars

2022

2021

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Actuarial losses (gains)

(10)

Deferred income tax expense (recovery)

(1)

AOCI, net of tax

(9)

(1)

Regulatory assets

336

192

AOCI, net of tax and regulatory assets

358

230

Benefit Cost Components

Emera's net periodic benefit cost included the following:

As at

Year ended December 31

millions of dollars

2022

2021

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Service cost

Interest cost

Expected return on plan assets

(144)

(132)

(1)

Current year amortization of:

Actuarial losses

Regulatory assets (liability)

Settlement, curtailments

Total

The expected return on plan assets is determined based on the market-related value of plan assets of

2,482

million as at January 1, 2022 (2021 – $

2,151

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

Fixed income

35%

50%

Equities:

Canadian

17%

Non-Canadian

36%

60%

Non-Canadian Pension Plans

Asset Class

Target Range at Market

Weighted average

Fixed income

30%

50%

Equities

50%

70%

Pension Plan assets are overseen by the respective Management Pension Committees in the sponsoring

companies. All pension investments are in accordance with policies approved by the respective Board of

Directors of each sponsoring company.

The following tables set out the classification of the methodology used by the Company to fair value its

investments:

millions of dollars

NAV

Level 1

Level 2

Total

Percentage

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

As at

December 31, 2021

Cash and cash equivalents

Net in-transits

(84)

(3)

Equity securities:

Canadian equity

United States equity

366

Other equity

215

Fixed income securities:

Government

132

Corporate

117

Other

Mutual funds

Other

(1)

Open-ended investments

measured at NAV

(1)

952

Common collective trusts

measured at NAV

(2)

750

Total

1,702

749

251

2,702

100

(1) 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 honor 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 honor

subscription and redemption activity regularly.

Refer to note 16 for more information on the fair value hierarchy and inputs used to measure fair value.

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 exceptions to this is the NMGC Retiree Medical Plan, which is fully funded.

Investments in Emera

As at December 31, 2022 and 2021, the 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 the expected cash flows for defined benefit pension and other post-retirement

benefit plans:

millions of dollars

Defined benefit

pension plans

Non-pension

benefit plans

Expected employer contributions

2023

Expected benefit payments

2023

164

2024

161

2025

168

2026

172

2027

178

2028 – 2032

919

105

Assumptions

The following table shows the assumptions that have been used in accounting for defined benefit

pension and other post-retirement benefit plans:

2022

2021

(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

5.33

5.31

3.05

2.81

Discount rate - future service

5.34

5.32

3.18

2.92

Rate of compensation increase

3.62

3.61

3.31

3.29

Health care trend

- initial (next year)

5.40

5.09

- ultimate

3.77

- year ultimate reached

2043

2042

Benefit cost for year ended December 31:

Discount rate - past service

3.05

2.81

2.49

2.48

Discount rate - future service

3.18

2.92

2.64

2.51

Expected long-term return on plan assets

6.07

1.32

5.86

Rate of compensation increase

3.31

3.29

2.89

3.04

Health care trend

- initial (current year)

5.09

5.64

- ultimate

3.77

4.35

- year ultimate reached

2042

2038

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 defined contribution pension plan for certain employees. The Company’s

contribution for the year ended December 31, 2022 was $

million (2021 – $

million).

22.

GOODWILL

The change in goodwill for the year ended December 31 is due to the following:

millions of dollars

2022

2021

Balance, January 1

5,696

5,720

GBPC impairment charge

(1)

(73)

Change in FX rate

389

(24)

Balance, December 31

6,012

5,696

(1) At the beginning of the period, Emera's accumulated impairment charges related to GBPC were $

million.

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, 2022, primarily relates to TECO Energy. Emera’s

reporting units with goodwill are Tampa Electric, PGS, NMGC, and GBPC.

In 2022, Emera performed a qualitative impairment assessment for Tampa Electric and PGS, concluding

that the fair value of the reporting units exceeded their respective carrying amounts, and as such, no

quantitative assessments were performed and

impairment charges were recognized. For the NMGC

reporting unit, Emera elected to bypass a qualitative assessment and performed a quantitative

impairment assessment using a combination of the income approach and market approach. This

assessment estimated that the fair value of the NMGC reporting unit exceeded its carrying amount,

including goodwill. As a result of this assessment,

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, as this reporting unit is sensitive to

changes in assumptions due to limited excess of fair value over carrying amount, including goodwill.

Although the cash flows of GBPC have not changed significantly compared to previous periods, it was

determined that the fair value did not exceed its carrying amount, including goodwill, primarily due to an

increase in discount rates. The discount rate for the reporting unit was negatively impacted by changes in

the macro-economic environment, including the risk-free rate assumption. 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 “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

2022

Weighted

average

interest rate

2021

Weighted

average

interest rate

Tampa Electric Company ("TEC")

Advances on term, revolving and accounts receivable facilities

1,380

5.00

945

0.58

Emera

Non-revolving term facilities

796

5.19

400

0.96

Bank indebtedness

TECO Finance

Advances on revolving credit and term facilities

481

5.47

355

1.20

NMGC

Advances on revolving credit facilities

5.15

1.20

GBPC

Advances on revolving credit facilities

5.25

NSPI

Bank indebtedness

Short-term debt

2,726

1,742

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

2022

2021

TEC - Unsecured committed revolving credit facility

2026

1,084

1,014

TECO Energy/TECO Finance - revolving credit facility

2026

542

507

Emera - non-revolving term facility

2023

400

Emera - non-revolving term facility

2023

400

TEC - Unsecured non-revolving facility

2023

542

634

NMGC - revolving credit facility

2026

169

158

GBPC - revolving credit facility

on demand

Total

3,155

2,729

Less:

Advances under revolving credit and term facilities

2,731

1,735

Letters of credit issued within the credit facilities

Total advances under available facilities

2,735

1,739

Available capacity under existing agreements

420

990

The weighted average interest rate on outstanding short-term debt at December 31, 2022 was

5.01

per

cent (2021 –

0.83

per cent).

Recent Significant Financing Activity by Segment

Florida Electric Utilities

On December 13, 2022, TEC amended its 364-day non-revolving term credit facility to extend the

maturity date from

December 16, 2022

December 13, 2023

and reduced the facility amount from $

500

million USD to $

400

million USD. There were no other significant changes in commercial terms from the

prior agreement.

Other

On December 16, 2022, Emera amended its $

400

million non-revolving term credit facility to extend the

maturity from

December 16, 2022

December 16, 2023

. There were no other significant changes in

commercial terms from the prior agreement.

On August 2, 2022, Emera entered into a $

400

million non-revolving term facility which matures on

August 2, 2023

. The credit agreement contains customary representation and warranties, events of

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

advances, plus a margin.

24.

OTHER CURRENT LIABILITIES

As at

December 31

millions of dollars

2022

2021

Accrued charges

174

157

Nova Scotia Cap-and-Trade Program provision (note 7)

172

Accrued interest on long-term debt

Pension and post-retirement liabilities (note 21)

Sales and other taxes payable

Income tax payable

Other

579

366

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

2022

2021

Maturity

2022

2021

Emera

Bankers acceptances, LIBOR loans

Variable

2027

403

378

Unsecured fixed rate notes

2.90%

2023

500

Fixed to floating subordinated notes (USD)

(2)

6.75%

2076

1,625

1,521

2,528

2,399

Emera Finance

Unsecured senior notes (USD)

3.65%

2024 - 2046

3,725

3,487

Tampa Electric

(3)

Fixed rate notes and bonds (USD)

4.15%

2024 - 2052

4,341

3,683

PGS

Fixed rate notes and bonds (USD)

3.78%

2024 - 2052

772

660

NMGC

Fixed rate notes and bonds (USD)

3.11%

2026 - 2051

521

488

Non-revolving term facility, floating rate

Variable

2024

108

101

629

589

NMGI

Fixed rate notes and bonds (USD)

3.64%

2024

203

190

NSPI

Discount notes

Variable

2024 - 2027

881

376

Medium term fixed rate notes

5.14%

2025 - 2097

2,665

3,546

3,041

EBP

Senior secured credit facility

Variable

2026

249

ECI

Secured senior notes (USD)

Variable

2026

Amortizing fixed rate notes (USD)

3.97%

2024 - 2026

100

104

Non-revolving term facility, floating rate

Variable

2027

Non-revolving term facility, fixed rate

2.05%

2.36%

2025 - 2026

101

Secured fixed rate senior notes

(4)

3.06%

4.43%

2023 - 2029

142

161

449

478

Adjustments

Fair market value adjustment - TECO Energy acquisition

(5)

Debt issuance costs

(126)

(121)

Amount due within one year

(574)

(462)

(698)

(580)

Long-Term Debt

15,744

14,196

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

(2) In 2022, the Company recognized $

110

million in interest expense (2021 – $

102

million) related to its fixed to floating

subordinated notes.

(3) A substantial part of Tampa

Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There

are

currently no bonds outstanding under Tampa

Electric’s first mortgage bond indenture.

(4) Notes are issued and payable in either USD or BBD.

(5) On acquisition of TECO Energy, Emera recorded

a fair market value adjustment on the unregulated long-term debt acquired.

The fair market value adjustment is amortized over the remaining term of the debt.

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

2022

2021

Emera – revolving credit facility

(1)

June 2027

900

NSPI - revolving credit facility

(1)

December 2027

800

600

NSPI - non-revolving credit facility

July 2024

400

NMGC - non-revolving credit facility

March 2024

108

ECI – revolving credit facilities

2023-2032

Total

2,219

1,527

Less:

Borrowings under credit facilities

1,396

770

Letters of credit issued inside credit facilities

124

Use of available facilities

1,408

894

Available capacity under existing agreements

811

633

(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, 2022

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 Utilities

On September 15, 2022, TEC repaid a $

250

million USD note upon maturity. The note was repaid using

existing credit facilities.

On July 12, 2022, TEC completed an issuance of $

600

million USD senior notes. The issuance included

300

million USD senior notes that bear an interest rate of

3.875

per cent with a maturity date of

July 12,

2024

, and $

300

million USD senior notes that bear an interest rate of

per cent with a maturity date of

July 15, 2052

Canadian Electric Utilities

On December 16, 2022, NSPI amended its revolving operating credit facility to extend the maturity date

from

December 16, 2026

December 16, 2027

and increase the amount of the facility from $

600

million

to $

800

million. There were no other significant changes in commercial terms from the prior agreement.

On July 15, 2022, NSPI entered into a $

400

million non-revolving term credit facility which matures on

July 15, 2024

. The credit facility contains customary representation and warranties, events of default and

financial and other covenants, and bears interest at Bankers’ Acceptances or prime rate advances, plus a

margin.

Gas Utilities and Infrastructure

On September 23, 2022, NMGC amended its $

million USD, unsecured, non-revolving term credit

facility to extend the maturity from

September 23, 2022

, to

March 22, 2024

. There were no other changes

in commercial terms from the prior agreement.

On June 30, 2022, Brunswick Pipeline amended its non-revolving credit agreement to extend the maturity

from

June 30, 2025

June 30, 2026

. There were no other changes in commercial terms from the prior

agreement.

Other Electric Utilities

On March 25, 2022, ECI amended its amortizing floating rate notes to extend the maturity from

March 25,

2022

March 25, 2027

. There were no other changes in commercial terms from the prior agreement.

Other

On December 16, 2022, Emera amended its $

900

million revolving operating credit facility to extend the

maturity date from

June 30, 2026

June 30, 2027

. There were no other significant changes in

commercial terms from the prior agreement.

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

2023

2024

2025

2026

2027

Thereafter

Total

Emera

500

1,625

403

2,528

Emera US Finance LP

407

1,016

2,302

3,725

Tampa Electric

356

3,985

4,341

PGS

721

772

NMGC

108

426

629

NMGI

203

NSPI

398

125

483

2,500

3,546

EBP

249

ECI

137

449

Total

574

1,613

262

3,110

946

9,937

16,442

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 fair value of any related ARO cannot be made.

The change in ARO for the years ended December 31 is as follows:

millions of dollars

2022

2021

Balance, January 1

174

178

Accretion included in depreciation expense

Change in FX rate

(1)

Additions

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

(2)

Liabilities settled

(1)

(13)

Revisions in estimated cash flows

(13)

Other

Balance, December 31

174

(1) Tampa Electric

produced ash and other by-products, collectively known as CCR's, at its Big Bend and Polk power stations. The

decrease in ARO in 2021 was due to the closure of CCR management facilities.

27.

COMMITMENTS AND CONTINGENCIES

Commitments

As at December 31, 2022, 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

2023

2024

2025

2026

2027

Thereafter

Total

Transportation

(1)

693

516

423

383

367

2,817

5,199

Purchased power

(2)

269

243

237

228

243

2,145

3,365

Fuel, gas supply and storage

1,161

282

138

1,627

Capital projects

264

358

Equity investment commitments

(3)

240

Other

149

142

132

189

703

2,776

1,272

934

701

657

5,152

11,492

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

Includes a commitment of

144

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 a final equity contribution to the LIL upon its commissioning. Once commissioned, the

commercial agreements between Emera and Nalcor require true ups to finalize the respective investment obligations

of the parties in

relation to the Maritime Link and LIL.

NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately

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 2022, the

UARB approved the collection of $

164

million from NSPI for the recovery of Maritime Link costs in 2023.

The timing and amounts payable to NSPML for the remainder of the

-year commitment period are

subject to UARB approval.

Emera has committed to obtain certain transmission rights 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, the

date the NS Block delivery obligation commenced, and continuing for

50 years

. As transmission rights are

contracted, the obligations are included within “Other” in the above table.

Legal Proceedings

TECO Guatemala Holdings (“TGH”)

Prior to Emera’s acquisition of TECO Energy in 2016, TGH, a wholly owned subsidiary of TECO Energy,

divested of its indirect investment in the Guatemala electricity sector, but retained certain claims against

the Republic of Guatemala (“Guatemala”). In 2013, TGH asserted an arbitration claim against Guatemala

with the International Centre for the Settlement of Investment Disputes (“ICSID”) under the Dominican

Republic Central America – United States Free Trade Agreement. The arbitration concerned TGH’s

allegation that Guatemala unfairly set the distribution tariff for a local distribution company which harmed

TGH’s investment in that company. A tribunal established by the ICSID ruled in favour of TGH (the “First

Award”) and, in November 2020, Guatemala made a payment of approximately $

million USD in full

and final satisfaction of the First Award.

On September 23, 2016, TGH had filed a request for resubmission to arbitration seeking damages in

addition to those awarded in the First Award. On May 13, 2020, an ICSID tribunal awarded TGH

additional damages and costs against Guatemala of more than $

million USD plus interest (the

“Second Award”). TGH subsequently requested a reconsideration of the interest quantum awarded in

connection with the Second Award. On October 16, 2020, the tribunal granted TGH’s request for

additional interest. The additional amount was approximately $

million USD. On February 12, 2021,

Guatemala filed an application with ICSID for annulment of the Second Award. On March 31, 2021, ICSID

constituted an ad hoc Committee to oversee the annulment proceeding. A three-day hearing was held

before the ad hoc Committee beginning on July 27, 2022.

On November 28, 2022, TGH and Guatemala entered into a settlement agreement with respect to the

Second Award. Pursuant to the settlement agreement, on December 15, 2022, Guatemala paid TGH $

million USD and the parties agreed to settle all outstanding disputes, concluding this matter. This amount

was recognized in “Other Income, net” on the Consolidated Statements of Income.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa

Electric and PGS divisions, is a potentially responsible party (“PRP”) for certain

superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the

joint and several liability associated with these sites presents the potential for significant response costs,

as at December 31, 2022, TEC estimated its financial liability to be $

million ($

million USD),

primarily at PGS. This estimate assumes that other involved PRPs are credit-worthy entities. This amount

has been accrued and is primarily reflected in the long-term liability section under “Other long-term

liabilities” on the Consolidated Balance Sheets. The environmental remediation costs associated with

these sites are expected to be paid over many years.

The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates

to perform the work are based on TEC’s 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, TEC could be liable for more than TEC’s 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 fair value 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 established a

Risk and Sustainability Committee (‘RSC”) in September 2021. The RSC’s mandate includes oversight of

the Company’s Enterprise Risk Management framework, including the identification, assessment,

monitoring and management of enterprise risks. It also includes oversight of the Company’s approach to

sustainability and its performance relative to its sustainability objectives.

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. The agreement provides for a predetermined toll

increase in the fifth and fifteenth year of the contract.

Regulators administer legislation covering material aspects of the utilities’ businesses, including 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. Costs

and investments can be recovered upon approval by the respective regulator as an adjustment to rates

and/or riders, which normally requires 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 employ a collaborative

regulatory approach through 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 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.

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 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 the legislative environment, political interference in the regulatory process, the

ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to

climate change-related impacts, including increased frequency and severity of hurricanes and other

severe weather events. A decrease in a credit rating could result in higher interest rates in future

financings, increased borrowing costs under certain existing credit facilities, limit access to the

commercial paper market or limit the availability of adequate credit support for subsidiary operations. For

certain derivative instruments, if the credit ratings of the Company were reduced below investment grade,

the full value of the net liability of these positions could be required to be posted as collateral. 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.

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 ROE’s 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.

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.

Commodity Price Risk

The Company’s utility fuel supply 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 has further

helped manage commodity price risk, as the regulatory framework for the Company’s rate-regulated

subsidiaries permits the recovery of prudently incurred fuel and gas costs. There is no assurance that

such mechanisms and regulatory frameworks will continue to exist in the future. Prolonged and

substantial increases in fuel prices could result in decreased rate affordability, increased risk of recovery

of costs or regulatory assets, and/or negative impacts on customer consumption patterns and sales.

Emera Energy Marketing and Trading

Emera Energy has employed further measures to manage commodity risk. The majority of Emera

Energy’s portfolio of electricity and gas marketing and trading contracts and, in particular, its natural gas

asset management arrangements, are contracted on a back-to-back basis, avoiding any material long or

short commodity positions. However, the portfolio is subject to commodity price risk, particularly with

respect to basis point differentials between relevant markets in the event of an operational issue or

counterparty default. Changes in commodity prices can also result in increased collateral requirements

associated with physical contracts and financial hedges, resulting in higher liquidity requirements and

increased costs to the business.

measure commodity price risk exposure, Emera Energy employs a number of controls and processes,

including an estimated VaR analysis of its exposures. The VaR

amount represents an estimate of the

potential change in fair value 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 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, 2022

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 up to $

million USD

relating to outstanding notes of GBPC

. The

guarantee for the notes will

expire in May 2023

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

(“NSPEMI”), in the amount of $

119

million USD (2021 – $

118

million USD) with terms of varying lengths.

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

145

million USD

(December 31, 2020 – $

148

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 2023. The amount committed

as at December 31, 2022 was $

million (December 31, 2021 – $

million).

Collaborative Arrangements

For the years ended December 31, 2022 and 2021, 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. In

2022, NSPI recognized $

million net expense (2021 – $

million) in “Regulated fuel for generation and

purchased power” and $

million (2021 – $

million) in OM&G.

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, 2022

December 31, 2021

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

1.1802

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

1.2250

25.00

12,000,000

295

12,000,000

295

Series J

1.0625

25.00

8,000,000

196

8,000,000

196

Series L

1.1500

26.00

9,000,000

222

9,000,000

222

Total

58,000,000

1,422

58,000,000

1,422

Characteristics of the First Preferred Shares:

First Preferred Shares

(1)(2)

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

4.100

1.1802

2.65

August 15, 2023

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

4.900

1.2250

4.90

August 15, 2023

25.00

Series I

Series J

4.250

1.0625

4.25

May 15, 2026

25.00

Series K

Perpetual fixed rate

Series E

(5)

4.500

1.1250

25.00

Series L

(6)

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

4.9

0 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, 2023, February 15, 2025 and August 15, 2023, 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) First Preferred Shares, Series E are redeemable at $

25.00

per share.

(6) 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 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.

29.

NON-CONTROLLING INTEREST IN SUBSIDIARIES

As at

December 31

millions of dollars

2022

2021

Preferred shares of GBPC

Domlec

(1)

(1) On March 31, 2022, Emera disposed its interest in Domlec. For further details, refer to note 4.

Preferred shares of GBPC:

Authorized:

10,000

non-voting cumulative redeemable variable perpetual preferred shares.

2022

2021

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

2022

2021

Changes in non-cash working capital:

Inventory

(214)

(84)

Receivables and other current assets

(1)

(636)

(364)

Accounts payable

423

289

Other current liabilities

(2)

193

Total non-cash working capital

(234)

(152)

(1) Includes $(

162

) million related to the January 2023 settlement of NMGC gas hedges. Offsetting regulatory liability is included

operating cash flow before working capital resulting in no impact to net cash provided by operating activities.

(2) Includes $

172

million related to the Nova Scotia Cap-and-Trade program. For further detail, refer to note 7.

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.

Supplemental disclosure of cash paid (received):

Interest

699

603

Income taxes

Supplemental disclosure of non-cash activities:

Common share dividends reinvested

237

214

Reclassification of long-term debt to short-term debt

500

Decrease in accrued capital expenditures

(13)

(45)

Supplemental disclosure of operating activities:

Net change in short-term regulatory assets and liabilities

(157)

(108)

31.

STOCK-BASED COMPENSATION

Employee Common Share Purchase Plan and Common Shareholders Dividend

Reinvestment and Share Purchase Plan

Eligible employees may participate in Emera’s Employee Common Share Purchase Plan. As of

December 31, 2022, 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 the reinvestment of dividends for all participants except for where it is 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, 2022, Emera is in compliance with this requirement.

Compensation cost for shares issued under the Employee Common Share Purchase Plan for the year

ended December 31, 2022 was $

million (2021 – $

million) and is included in OM&G on the

Consolidated Statements of Income.

The Company also has a Common Shareholders Dividend Reinvestment and Share Purchase Plan

(“Dividend Reinvestment Plan”), which provides an opportunity for shareholders 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 2022.

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, 2022, Emera is 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 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 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. 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 fair values per stock option along with the assumptions

incorporated into the valuation models for options granted, for the year-ended December 31:

2022

2021

Weighted average fair value per option

5.35

3.63

Expected term

(1)

years

Risk-free interest rate

(2)

1.79

0.60

Expected dividend yield

(3)

4.55

5.00

Expected volatility

(4)

18.87

19.14

(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 2022:

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, 2021

2,590,304

48.48

1,452,475

3.18

Granted

467,100

58.26

467,100

5.35

Exercised

(203,525)

43.87

N/A

Vested

N/A

(571,175)

2.83

Options outstanding December 31, 2022

2,853,879

50.41

1,348,400

4.08

Options exercisable December 31, 2022

(2)(3)

1,505,479

46.59

(1) As at December 31, 2022, 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 (2021 – $

million,

years).

(2) As at December 31, 2022, the weighted average remaining term of vested options was

years with an aggregate intrinsic value of

million (2021 –

years, $

million).

(3) As at December 31, 2022, the fair value of options that vested in the year was $

million (2021 – $

million).

Compensation cost recognized for stock options for the year ended December 31, 2022 was $

million

(2021 – $

million), which is included in OM&G on the Consolidated Statements of Income.

As at December 31, 2022, cash received from option exercises was $

million (2021 – $

million). The

total intrinsic value of options exercised for the year ended December 31, 2022 was $

million (2021 – $

million). The range of exercise prices for the options outstanding as at December 31, 2022 was $

32.35

60.03

(2021 – $

32.35

to $

60.03

Share Unit Plans

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

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

Deferred Share Unit Plans

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

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

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

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

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

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

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

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

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

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

redeemed.

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

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

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

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

the applicable guidelines are met.

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

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

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

dividends paid on an equivalent number of Emera common shares. 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, 2022

is presented in the following table:

Employee

DSU

Weighted

Average

Grant Date

Fair Value

Director

DSU

Weighted

Average

Grant Date

Fair Value

Outstanding as at December 31, 2021

610,601

39.22

614,365

43.80

Granted including DRIP

76,252

52.42

104,465

57.89

Exercised

(59,630)

31.57

(54,572)

46.04

Outstanding and exercisable as at December 31, 2022

627,223

41.55

664,258

45.83

Compensation cost recovery recognized for employee and director DSU’s for the year ended December

31, 2022 was $

million (2021 – $

million expense). Tax

expense related to this compensation cost

recovery for share units realized for the year ended December 31, 2022 was $

million (2021 – $

million

tax recovery). The aggregate intrinsic value of the outstanding shares for the year ended December 31,

2022 for employees was $

million (2021 – $

million). The aggregate intrinsic value of the outstanding

shares for the year ended December 31, 2022 for directors was $

million (2021 – $

million). Cash

payments made during the year ended December 31, 2021 associated with the DSU plan was $

million

(2021 – $

million).

Performance Share Unit Plan

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

through the PSU 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.

A summary of the activity related to employee PSUs for the year ended December 31, 2022 is presented

in the following table:

Employee PSU

Weighted Average

Grant Date Fair Value

Aggregate intrinsic value

Outstanding as at December 31, 2021

951,935

48.60

Granted including DRIP

242,462

59.30

Exercised

(357,960)

42.85

Forfeited

(145,991)

44.28

Outstanding as at December 31, 2022

690,446

56.24

Compensation cost recognized for the PSU plan for the year ended December 31, 2022 was $

million

(2021 – $

million). Tax

benefits related to this compensation cost for share units realized for the year

ended December 31, 2022 were $

million (2021 – $

million). Cash payments made during the year

ended December 31, 2021 associated with the PSU plan was $

million (2021 – $

million).

Restricted Share Unit Plan

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

through the RSU 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.

A summary of the activity related to employee RSUs for the year ended December 31, 2022 is presented

in the following table:

Employee RSU

Weighted Average

Grant Date Fair Value

Aggregate intrinsic value

Outstanding as at December 31, 2021

343,952

54.64

Granted including DRIP

180,426

59.30

Exercised

(134)

54.63

Forfeited

(15,776)

56.08

Outstanding as at December 31, 2022

508,468

56.25

Compensation cost recognized for the RSU plan for the year ended December 31, 2022 was $

million

(2021 – $

million). Tax

benefits related to this compensation cost for share units realized for the year

ended December 31, 2022 were $

million (2021 – $

million). Cash payments made during the year

ended December 31, 2022 associated with the RSU plan was

nil

(2021–

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.

BLPC has established a Self-Insurance Fund (“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, 2022

December 31, 2021

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)

501

533

33.

COMPARATIVE

INFORMATION

These financial statements contain certain reclassifications of prior period amounts to be consistent with

the current period presentation, with no effect on net income.

34.

SUBSEQUENT EVENTS

These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to

the balance sheet date through February 23, 2023, the date the financial statements were issued.