EX-99.3

EMERA INCORPORATED

Consolidated

Financial Statements

December 31, 2021 and 2020

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 14, 2022

“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, 2021 and 2020, 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, 2021 and 2020, and the consolidated results

of its operations and its consolidated cash

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

31, 2021, 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 $2.6 billion in regulatory assets and $2.1 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

property, plant and

equipment, 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 recovery on costs incurred,

of the disallowance of part of the cost of

recently completed property,

plant and equipment and construction work in

progress, 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, property,

plant and equipment, 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 and disclosure of derivative financial

instruments

Description of the

Matter

Held-for-trading (“HFT”) derivative assets of $241 million

and liabilities of

$850 million, disclosed in note 15 to the consolidated financial

statements,

are measured at fair value. The Company recognized $138 million

realized and unrealized losses 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, the Company’s own

credit risk and discount rates.

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, credit metrics and discount rates 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 14, 2022

Emera Incorporated

Consolidated Statements of Income

For the

Year ended December 31

millions of Canadian dollars (except per share amounts)

2021

2020

Operating revenues

Regulated electric

4,665

4,442

Regulated gas

1,261

1,034

Non-regulated

(161)

Total

operating revenues (note 6)

5,765

5,506

Operating expenses

Regulated fuel for generation and purchased power (notes 17 and 19)

1,763

1,420

Regulated cost of natural gas

472

293

Non-regulated fuel for generation and purchased power

(1)

Operating, maintenance and general

1,369

1,419

Provincial, state, and municipal taxes

330

317

Depreciation and amortization

902

881

Impairment charges

Total

operating expenses

4,835

4,359

Income from operations

930

1,147

Income from equity investments (note 8)

143

149

Other income, net (note 9)

708

Interest expense, net

611

679

Income before provision for income taxes

555

1,325

Income tax (recovery) expense (note 10)

(6)

341

Net income

561

984

Non-controlling interest in subsidiaries

Preferred stock dividends

Net income attributable to common shareholders

510

938

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

Basic

257

248

Diluted

258

248

Earnings per common share (note 12)

Basic

1.98

3.78

Diluted

1.98

3.78

Dividends per common share declared

2.5750

2.4750

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 Canadian dollars

2021

2020

Net income

561

984

Other comprehensive income (loss), net of tax

Foreign currency translation adjustment

(1)

(42)

(201)

Unrealized gains on net investment hedges

(2) (3)

Cash flow hedges

Net derivative gains

(4)

Less: reclassification adjustment for (gains) losses included in income

(1)

Net effects of cash flow hedges

Net change in unrecognized pension and post-retirement benefit obligation

(5)

124

(1)

Other comprehensive income (loss)

(6)

104

(174)

Comprehensive income

665

810

Comprehensive income attributable to non-controlling interest

Comprehensive Income of Emera Incorporated

664

809

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

Net of tax expense of $

million (2020 - $

million recovery) for the year ended December

31, 2021.

2) The Company has designated $

1.2

billion United States dollar denominated Hybrid

Notes as a hedge of the foreign currency

exposure of its net investment in United States

dollar denominated operations.

Net of tax expense of $

million (2020 - $

million expense) for the year ended December

31, 2021.

Net of tax expense of $

million (2020 -

nil

) for the year ended December 31, 2021.

Net of tax expense of $

million (2020 - $

million recovery) for the year ended December

31, 2021.

Net of tax expense of $

million (2020 - $

million expense) for the year ended December

31, 2021.

Emera Incorporated

Consolidated Balance Sheets

As at

December 31

millions of Canadian dollars

2021

2020

Assets

Current assets

Cash and cash equivalents

394

220

Restricted cash (note 32)

Inventory (note 14)

538

453

Derivative instruments (notes 15 and 16)

195

Regulatory assets (note 7)

253

165

Receivables and other current assets (note 18)

1,733

1,233

3,136

2,178

Property, plant and equipment,

net of accumulated depreciation

and amortization of $

8,739

and $

8,714

, respectively (note 20)

20,353

19,535

Other assets

Deferred income taxes (note 10)

295

209

Derivative instruments (notes 15 and 16)

106

Regulatory assets (note 7)

2,313

1,419

Net investment in direct financing lease (note 19)

462

475

Investments subject to significant influence (note 8)

1,382

1,346

Goodwill (note 22)

5,696

5,720

Other long-term assets

501

327

10,755

9,521

Total assets

34,244

31,234

Emera Incorporated

Consolidated Balance Sheets – Continued

As at

December 31

millions of Canadian dollars

2021

2020

Liabilities and Equity

Current liabilities

Short-term debt (note 23)

1,742

1,625

Current portion of long-term debt (note 25)

462

1,382

Accounts payable

1,485

1,148

Derivative instruments (notes 15 and 16)

533

251

Regulatory liabilities (note 7)

290

129

Other current liabilities (note 24)

366

340

4,878

4,875

Long-term liabilities

Long-term debt (note 25)

14,196

12,339

Deferred income taxes (note 10)

1,868

1,629

Derivative instruments (notes 15 and 16)

149

Regulatory liabilities (note 7)

1,765

1,832

Pension and post-retirement liabilities (note 21)

370

453

Other long-term liabilities (note 8 and 26)

868

781

19,216

17,121

Equity

Common stock (note 11)

7,242

6,705

Cumulative preferred stock (note 28)

1,422

1,004

Contributed surplus

Accumulated other comprehensive income (loss) (note 13)

(79)

Retained earnings

1,348

1,495

Total

Emera Incorporated equity

10,116

9,204

Non-controlling interest in subsidiaries

(note 29)

Total

equity

10,150

9,238

Total liabilities and equity

34,244

31,234

Commitments and contingencies

(note 27)

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

Approved on behalf of the Board of Directors

“M. Jacqueline Sheppard”

“Scott Balfour”

Chair of the Board

President and Chief Executive Officer

Emera Incorporated

Consolidated Statements of Cash Flows

For the

Year ended December 31

millions of Canadian dollars

2021

2020

Operating activities

Net income

561

984

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

Depreciation and amortization

915

899

Income from equity investments, net of dividends

(69)

(76)

Allowance for equity funds used during construction

(61)

(45)

Deferred income taxes, net

(37)

381

Net change in pension and post-retirement liabilities

(23)

Regulated fuel adjustment mechanism

(166)

(94)

Net change in fair value of derivative instruments

404

(36)

Net change in regulatory assets and liabilities

(176)

(87)

Net change in capitalized transportation capacity

(107)

Impairment charges

Gain on sale, excluding transaction costs

(603)

Other operating activities, net

Changes in non-cash working capital (note 30)

(152)

217

Net cash provided by operating activities

1,185

1,637

Investing activities

Additions to property, plant and equipment

(2,359)

(2,623)

Proceeds from dispositions (note 4)

1,401

Other investing activities

(2)

Net cash used in investing activities

(2,332)

(1,224)

Financing activities

Change in short-term debt, net

(155)

385

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

640

399

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

(377)

(688)

Proceeds from long-term debt, net of issuance costs

2,554

428

Retirement of long-term debt

(1,660)

(513)

Net proceeds (repayments) under committed credit facilities

(203)

Issuance of common stock, net of issuance costs

317

285

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

416

Dividends on common stock

(443)

(409)

Dividends on preferred stock

(50)

(45)

Other financing activities

(13)

(11)

Net cash provided by (used in) financing activities

1,311

(372)

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

(1)

(61)

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

163

(20)

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

254

274

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

417

254

Cash, cash equivalents and restricted cash consists of:

Cash

237

220

Short-term investments

157

Restricted cash

Cash, cash equivalents and restricted cash

417

254

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

Accumulated

Other

Comprehensive

Non-

Common

Preferred

Contributed

Income

Retained

Controlling

Total

Stock

Surplus

(Loss)

(1)

Earnings

Interest

Equity

millions of Canadian dollars

Balance, December 31, 2020

6,705

1,004

(79)

1,495

9,238

Net income of Emera

incorporated

560

561

Other comprehensive income,

net of tax expense of $

million

104

Dividends declared on preferred

stock (note 28)

(50)

Dividends declared on common

stock ($

2.575

0/share)

(657)

Issuance of preferred shares,

net of after-tax issuance costs

(note 28)

418

Common stock issued under

purchase plan

235

Issuance of common stock, net

of after-tax issuance costs

284

Senior management stock

options exercised

Other

(1)

Balance, December 31, 2021

7,242

1,422

1,348

10,150

Balance, December 31, 2019

6,216

1,004

1,173

8,601

Net income of Emera Inc

983

984

Other comprehensive loss, net of

tax expense of $

million

(174)

Dividends declared on preferred

stock (note 28)

(45)

Dividends declared on common

stock ($

2.4750

/share)

(609)

Common stock issued under

purchase plan

215

Issuance of common stock, net of

after-tax issuance costs

251

Senior management stock

options exercised

(1)

Adoption of credit losses

accounting standard

(7)

Other

(2)

Balance, December 31, 2020

6,705

1,004

(79)

1,495

9,238

(1) Accumulated Other Comprehensive Income (Loss)

("AOCI") ("AOCL")

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

Emera Incorporated

Notes to the Consolidated Financial Statements

As at December 31, 2021 and 2020

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, 2021, Emera’s reportable segments

include the following:

●

Florida Electric Utility,

which consists of Tampa

Electric,

a vertically integrated regulated electric

utility, serving approximately

810,600

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

536,000

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 being developed

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 AFUDC) transmission project, including

two

170

-kilometre sub-sea cables, connecting the island

of Newfoundland and Nova

Scotia. This project went in service on January 15, 2018;

and

●

37.4

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 to enable the transmission of Muskrat Falls energy

between Labrador and

the island of Newfoundland. Construction of the LIL has

been completed and Nalcor

recognized the first flow of energy from Labrador to Newfoundland

in June 2018.

Muskrat Falls generators are completed and available fo

service and Nalcor is

forecasting it will achieve final commissioning of Muskrat

Falls and LIL in the first half

of 2022. For further details, refer to note 27.

●

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

132,000

customers;

●

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

integrated regulated electric

utility on Grand Bahama Island, serving approximately

19,000

customers;

●

51.9

per cent interest in Dominica Electricity Services

Ltd. (“Domlec”), a vertically integrated

regulated electric utility on the island of Dominica, serving

approximately

35,700

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.

On March 24, 2020, Emera completed the sale of Emera

Maine which was previously included in the

Other Electric Utilities segment. Refer to note 4.

●

Gas Utilities and Infrastructure, which includes:

●

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

serving approximately

445,000

customers across Florida;

●

New Mexico Gas Company,

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

serving

approximately

542,000

customers in New Mexico;

●

SeaCoast Gas Transmission, LLC (“SeaCoast”),

a regulated intrastate natural gas

transmission company offering services in Florida;

●

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

Canada,

which expires in 2034; and

●

12.9

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

1,400

-kilometre

pipeline, that transports natural gas throughout markets

in Atlantic Canada and the

northeastern United States.

●

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

633

MW pumped storage hydroelectric facility in northwestern

Massachusetts.

●

Emera Reinsurance Limited, a captive insurance company providing

insurance and

reinsurance to Emera and certain affiliates;

●

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.

In 2020, the outbreak of COVID-19, resulted in governments

worldwide enacting emergency measures to

combat the spread of the virus. Management considered the

impact of COVID-19 in the Company’s

estimates and results and concluded the financial statements as

of and for the year ended December 31,

2021 were not materially impacted.

Basis of Presentation

These consolidated financial statements are prepared

and presented in accordance with United States

Generally Accepted Accounting Principles (“USGAAP”).

In the opinion of management, these

consolidated financial statements 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, unless

otherwise indicated.

Principles of Consolidation

The consolidated financial statements of Emera include

the accounts of Emera Incorporated, its majority-

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

in which Emera is the primary beneficiary.

For

further details on VIEs, refer to note 32. Emera uses the

equity method of accounting to record

investments in which the Company has the ability to exercise

significant influence, and for VIEs in which

Emera is not the primary beneficiary.

The Company performs ongoing analysis to assess whether

it holds any VIEs or whether any

reconsideration events have arisen with respect to existing

VIEs.

identify potential VIEs,

management reviews contractual and ownership arrangements

such as leases, long-term purchase

power agreements, tolling contracts, guarantees, jointly

owned facilities and equity investments. VIEs

of which the Company is deemed the primary beneficiary

must be consolidated. The primary

beneficiary of a VIE has both the power to direct the activities

of the 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.

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 property, plant

and equipment, regulatory assets,

regulated fuel for generation and purchased power,

or operating, maintenance and general (“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 the 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, 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.

Management has analyzed the impact of the COVID-19 pandemic

on its estimates and assumptions and

concluded that no material adjustments were required

for the year ended December 31, 2021.

The extent of the future impact of COVID-19 on the Company’s

financial results and business operations

cannot be predicted at this time and will depend on future

developments, including the duration and

severity of the pandemic, timing and effectiveness

of vaccinations, further potential government actions

and future economic activity and energy usage. Actual

results may differ significantly from these

estimates.

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 Canadian dollars 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 the exchange rates in effect at the

balance sheet date and the results of operations

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 United States dollar

denominated debt held in Canadian dollar

functional currency companies as hedges of net investments

in United States dollar 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 Revenue

Electric 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 is delivered to customers over time as the customer

simultaneously receives and consumes the

benefits of the electricity.

Electric revenues are recognized on an accrual basis and include

billed and

unbilled revenues. Revenues related to the sale of electri

city 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 delivered

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”) 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.

Regulated Gas Revenue

Gas revenues, including energy charges, demand charges,

basic facilities charges and applicable

clauses and riders, are recognized when obligations under the

terms of a contract are satisfied, which is

when gas is delivered to customers over time as the customer

simultaneously receives and consumes the

benefits of the gas. Gas revenues are recognized on an

accrual basis and include billed and unbilled

revenues. Revenues related to the distribution and sale

of 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.

At the end of each reporting period, the 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 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 usage,

weather, and inter-period

changes to customer

classes.

Non-regulated Revenue

Marketing and trading margins are comprised of Emera

Energy’s corresponding purchases and sales

natural gas and electricity,

pipeline capacity costs and energy asset management revenues.

Revenues

are recorded when obligations under terms of a 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 terms of a 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 (“ROU”) 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

Property, plant and

equipment are recorded at original cost, including

allowance for funds used during

construction (“AFUDC”) or capitalized interest, net of contributions

received in aid of construction.

The cost of additions, including betterments and replacements

of units of property,

plant and equipment,

are included in “Property,

plant and equipment”. When units of regulated property,

plant and equipment

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 property,

plant and equipment occurs, gains and losses are

included in income as the

dispositions occur.

The cost of property,

plant and equipment represents the original cost of

materials, contracted services,

direct labour, AFUDC for regulated

property or interest for non-regulated property,

asset retirement

obligations (“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 are expensed as incurred.

Planned major maintenance projects that do not

increase the overall life of the related assets are expensed.

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

the appropriate 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. 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,

BLPC and Domlec 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 information, 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 and PGS have 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 property,

plant and equipment, depending on the nature of

the item being economically hedged. Tran

sportation 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

“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 is exposed to credit risk with respect to

amounts receivable from customers. Credit

assessments may be conducted on new customers. Deposits

are requested on accounts in accordance

with the Company’s policy.

The Company also maintains provisions for expected credit losses,

which are

assessed on a regular basis.

Management estimates credit losses related to accounts

receivable after 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.

The economic impact of COVID-19 in the service territories

in which Emera operates, has impacted the

aging of customer receivables resulting in higher allowances

for credit losses related to customer

receivables, however it has not had a material impact on earnings.

Inventory

Fuel and materials inventories are valued using the weighted

-average cost method. These inventories are

carried 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.

Management considered whether the potential impacts

of the COVID-19 pandemic on undiscounted

future cash flows could indicate that long-lived assets

are not recoverable. As at December 31, 2021,

there are no indications of impairment of Emera’s

long-lived assets.

No impairment charges were recognized during the year

ended December 31, 2021. In 2020, impairment

charges of $

million ($

million after tax) were recognized on certain assets and

recorded in

“Impairment charges” in the Consolidated Statements of Income.

Goodwill

Goodwill is not amortized but is subject to an annual assessment

for impairment at the reporting unit level

with interim impairment tests performed when impairment

indicators are present. Reporting units are

generally determined at the operating segment level or one

level below the operating segment level.

Reporting units with similar characteristics are grouped

for the purpose of determining impairment, if any,

of goodwill.

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 as

a reduction to goodwill and a charge to operating

expense. 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,

valuation of the reporting units' net

operating loss (“NOL”), utility sector market performance

and transactions, projected operating and

capital cash flows and the fair value of debt. Adverse changes

in assumptions described above could

result in a future material impairment of the goodwill assigned

to Emera’s reporting units with goodwill. As

part of the goodwill impairment assessment management considered

the potential impacts of the COVID-

19 pandemic on the future earnings of the reporting units.

As of December 31, 2021, $

5.6

billion of Emera’s goodwill was related to TECO

Energy (Tampa

Electric,

PGS and NMGC reporting units). Qualitative assessments

were performed for these reporting units 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.

As of December 31, 2021, $

million of Emera’s goodwill was related to GBPC.

In Q4 2021, the

Company performed a quantitative impairment assessment

for GBPC as this reporting unit is more

sensitive to changes in assumptions due to limited excess

of fair value over the carrying value. The

assessment estimated that the fair value of the reporting

unit exceeded its carrying value, including

goodwill, by approximately

per cent. For further detail, refer to note 22.

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, including the impact of COVID-19. 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. No impairment of equity

method investments was required in either 2021 or 2020.

Financial Assets

Equity investments, other than those accounted for under

the equity method of accounting, 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. No impairment of financial

assets was required in either 2021 or 2020.

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 property,

plant and equipment 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.

CHANGE IN ACCOUNTING POLICY

The new USGAAP accounting policies that are applicable to,

and adopted by the Company in 2021, are

described as follows:

Accounting for Convertible Instruments and Contracts

in an Entity’s Own Equity

The Company adopted Accounting Standard Update ("ASU") 2020-06, Debt - Debt with Conversion and

Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity

(Subtopic 815-40) effective January 1, 2021 using the modified retrospective approach. The standard

simplifies the accounting for convertible debenture debt instruments and convertible preferred stock, in

addition to amending disclosure requirements. The standard also updates guidance for the derivative

scope exception for contracts in an entity’s own equity and the related earnings per share guidance.

There was no material impact on the consolidated financial statements as a result of the adoption of this

standard.

Guaranteed Debt Securities Disclosure Requirements

The Company adopted ASU 2020-09, Debt (Topic 470): Amendments to SEC Paragraphs pursuant to

SEC Release No. 33-10762 effective December 31, 2021. The standard aligns with new SEC rules

relating to changes to the disclosure requirements for certain registered debt securities that are

guaranteed. The changes include simplifying and focusing the disclosure models, enhancing certain

narrative disclosures and permitting the disclosures to be made outside of the financial statements. As a

result of adopting this standard, the disclosures related to certain registered debt securities that are

guaranteed were amended and removed from the consolidated financial statements and added to

Management’s Discussion & Analysis.

FUTURE ACCOUNTING PRONOUNCEMENTS

The Company considers the applicability and impact of

all ASUs issued by the Financial Accounting

Standards Board (“FASB”). The

ASUs that have been issued by FASB,

but are not yet effective, were

assessed and determined to be either not applicable

to the Company or have an insignificant impact on

the consolidated financial statements.

DISPOSITIONS

On March 24, 2020, Emera completed the sale of

Emera Maine

for a total enterprise value of

approximately $

2.0

billion including cash proceeds of $

1.4

billion, transferred debt and working capital

adjustments. A gain on disposition of $

585

million ($

309

million after tax) net of transaction costs, was

recognized in the Other segment and included in “Other

income” on the Consolidated Statements of

Income.

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.

Emera’s

five

reportable segments are Florida Electric Utility,

Canadian Electric

Utilities, Other Electric Utilities, Gas Utilities and Infrastructure,

and Other.

Florida

Canadian

Other

Gas Utilities

Inter-

Electric

and

Segment

millions of Canadian dollars

Utility

Utilities

Infrastructure

Other

Eliminations

Total

For the year ended December 31, 2021

Operating revenues from

external customers (1)

2,718

1,501

445

1,276

(175)

5,765

Inter-segment revenues

(1)

(28)

Total operating revenues

2,724

1,501

445

1,280

(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

140

325

(16)

1,369

Depreciation and amortization

469

246

121

902

Income from equity investments

103

143

AFUDC - debt and equity

Interest expense, net

138

132

269

611

Internally allocated interest (2)

(13)

Income tax expense (recovery)

(150)

(6)

Net income (loss) attributable to

common shareholders

462

241

198

(412)

510

Capital expenditures

1,331

366

111

515

2,328

As at December 31, 2021

Total assets

17,903

7,418

1,402

6,666

2,034

(1,179)

(3)

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 inter-company

transactions have been eliminated on consolidation

except for certain

transactions between non-regulated and regulated entities

that have not been eliminated because management

believes the

elimination of these transactions would understate

property, plant and equipment, OM&G expenses, 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.

(3) Primarily relates to consolidated deferred tax reclassifications.

Deferred tax assets are reclassified and

netted with deferred tax

liabilities upon consolidation.

Florida

Canadian

Other

Gas Utilities

Inter-

Electric

and

Segment

millions of Canadian dollars

Utility

Utilities

Infrastructure

Other

Eliminations

Total

For the year ended December 31, 2020

Operating revenues from

external customers

(1)

2,473

1,494

474

1,051

5,506

Inter-segment revenues

(1)

(29)

Total operating revenues

2,480

1,494

474

1,058

(29)

5,506

Regulated fuel for generation

and purchased power

574

659

194

(7)

1,420

Regulated cost of natural gas

293

OM&G

552

282

151

334

115

(15)

1,419

Depreciation and amortization

455

236

111

881

Income from equity investments

149

AFUDC - debt and equity

Interest expense, net

151

139

301

679

Internally allocated interest (2)

(13)

Gain on sale, net of

transactions costs

585

Impairment charges

(25)

Income tax expense (recovery)

(8)

192

341

Net income attributable to

common shareholders

501

221

162

938

Capital expenditures

1,361

338

148

749

2,600

As at December 31, 2020

Total assets

16,889

6,752

1,365

6,067

1,234

(1,073)

(3)

31,234

Investments subject to

significant influence

1,176

129

1,346

Goodwill

4,455

1,194

5,720

(1) All significant inter-company balances and inter-company

transactions have been eliminated on consolidation

except for certain

transactions between non-regulated and regulated entities

that have not been eliminated because management

believes the

elimination of these transactions would understate

property, plant and equipment, OM&G expenses, 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.

(3) Primarily relates to consolidated deferred tax reclassifications.

Deferred tax assets are reclassified and

netted with deferred tax

liabilities upon consolidation.

Geographical Information

Revenues

(based on country of origin of the product

or service sold)

For the

Year ended December 31

millions of Canadian dollars

2021

2020

United States

3,754

3,522

Canada

1,566

1,569

Barbados

292

263

The Bahamas

110

112

Dominica

5,765

5,506

Property Plant and Equipment:

As at

December 31

millions of Canadian dollars

2021

2020

United States

14,978

14,353

Canada

4,440

4,304

Barbados

535

510

The Bahamas

322

289

Dominica

20,353

19,535

REVENUE

The following disaggregates the Company’s revenue

by major source:

Florida

Canadian

Other

Gas Utilities

Inter-

Electric

and

Segment

millions of Canadian dollars

Utility

Utilities

Infrastructure

Other

Eliminations

Total

For the year ended December 31, 2021

Regulated Electric Revenue

Residential

1,449

797

165

2,411

Commercial

754

407

232

1,393

Industrial

215

237

478

Other electric and regulatory

deferrals

289

323

Other (1)

(6)

Regulated electric revenue

2,724

1,501

445

(6)

4,665

Regulated Gas Revenue

Residential

642

Commercial

379

Industrial

(2)

Finance income (2)(3)

Other

121

(2)

119

Regulated gas revenue

1,265

(4)

1,261

Non-Regulated

Marketing and trading margin (4)

102

Energy sales

(21)

Other

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.

Florida

Canadian

Other

Gas Utilities

Inter-

Electric

and

Segment

millions of Canadian dollars

Utility

Utilities

Infrastructure

Other

Eliminations

Total

For the year ended December 31, 2020

Regulated Electric Revenue

Residential

1,365

806

179

2,350

Commercial

678

405

233

1,316

Industrial

178

224

434

Other electric and regulatory

deferrals

242

281

Other (1)

(7)

Regulated electric revenue

2,480

1,494

474

(7)

4,442

Regulated Gas Revenue

Residential

495

Commercial

275

Industrial

Finance income (2)(3)

Other

156

(7)

149

Regulated gas revenue

1,041

(7)

1,034

Non-Regulated

Marketing and trading margin (4)

Energy sales

(16)

Other

Mark-to-market (3)

(46)

(45)

Non-regulated revenue

(15)

Total operating revenues

2,480

1,494

474

1,058

(29)

5,506

(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, 2021, the

aggregate amount of the transaction price allocated to

remaining performance obligations was $

437

million (2020 – $

464

million). This amount includes $

142

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

2041

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 circumstanc

es. 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 Canadian dollars

2021

2020

Regulatory assets

Deferred income tax regulatory assets

1,045

887

Tampa

Electric capital cost recovery for early retired assets

657

Pension and post-retirement medical plan

291

394

Regulated fuel adjustment mechanism

145

NMGC winter event gas cost recovery

117

Cost recovery clauses

114

Storm restoration regulatory asset

Environmental remediations

Stranded cost recovery

Deferrals related to derivative instruments

Demand side management ("DSM") deferral

Unamortized defeasance costs

Other

2,566

1,584

Current

253

165

Long-term

2,313

1,419

Total

regulatory assets

2,566

1,584

Regulatory liabilities

Deferred income tax regulatory liabilities

863

933

Accumulated reserve - cost of remova

819

865

Deferrals related to derivative instruments

241

Storm reserve

Cost recovery clauses

Self-insurance fund (note 32)

Regulated fuel adjustment mechanism

Other

2,055

1,961

Current

290

129

Long-term

1,765

1,832

Total

regulatory liabilities

2,055

1,961

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.

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. See “Tampa

Electric Big Bend Modernization Project” below for further

information.

Pension and Post-Retirement Medical Plan

This asset is primarily related to the deferred costs of pension

and post-retirement benefits at Tam

Electric, PGS and NMGC. It is included in rate base and

earns a rate of return as permitted by the FPSC

and New Mexico Public Regulation Commission (“NMPRC”)

as applicable. It is amortized over the

remaining service life of plan participants.

Regulated Fuel Adjustment Mechanism

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 fuel adjustment mechanism (“FAM”)

regulatory asset or liability and recovered from or returned

to customers in a subsequent year.

approved on December 6, 2019 as part of NSPI’s

three-year fuel stability plan, differences

between

actual fuel costs and fuel revenues recovered from customers

for the years 2020 to 2022, will be

recovered or returned to customers after 2022. 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.

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. 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.

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 NMPRC, as

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

period.

Storm Restoration Regulatory Asset

This asset represents storm restoration costs, primarily

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. Additional details on the recovery are included

under the GBPC section below.

The balance

of the regulatory asset as at December 31, 2021 is $

million USD.

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.

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, operating,

maintenance or general or

property, plant and equipment,

depending on the nature of the item being economically hedged.

DSM Deferral

The UARB approved implementation of the 2015 DSM deferral set at $35 million in 2015 and recoverable

from customers over an 8-year period beginning in 2016.

The UARB directed EfficiencyOne, a franchisee

appointed by the Province of Nova Scotia to provide

NSPI with electricity efficiency and conservation

activities under the

Public Utilities Act

, to review

financing options through which EfficiencyOne

would borrow the 2015 deferral amount from

a commercial

lender in order to repay NSPI the amount it expended

on behalf of its customers in 2015. In December

2016, EfficiencyOne secured financing and $

million was advanced to NSPI to finance the 2015

DSM

deferral. In February 2017, EfficiencyOne advanced

an additional $

million to NSPI. As NSPI collects the

associated amounts from customers over the remaining

three years

, it will repay the balance to

EfficiencyOne. This has been set up as a liability in

“Other long-term liabilities” with the current portion

the liability included in “Other current liabilities” on the

Consolidated Balance Sheets.

Unamortized Defeasance Costs

Upon privatization in 1992, NSPI became responsible for

managing a portfolio of defeasance securities

held in trust that provide the principal and interest streams

to match the related defeased debt, which as

at December 31, 2021, totalled $

200

million (2020 – $

582

million). The excess of the cost of defeasance

investments over the face value of the related debt is deferred

on the balance sheet and amortized over

the life of the defeased debt as permitted by the UARB.

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

retire its property,

plant and equipment. Non-ARO COR represent estimated

funds received from

customers through depreciation rates to cover future

COR of property, plant

and equipment 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.

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 2021, 2020 and 2019,

Tampa

Electric incurred storm restoration

preparation costs for multiple hurricanes of approximately $

million USD, which was charged to the

storm reserve regulatory liability

Regulatory Environments

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.

Tampa

Electric’s approved regulated return on equity

(“ROE”) range for 2021 and 2020 was

9.25

per cent

11.25

per cent based on an allowed equity capital structure

per cent. An ROE of

10.25

per cent is

used for the calculation of the return on investments for

clauses.

Beginning in 2022, Tampa

Electric’s

approved regulated ROE range is

9.00

per cent to

11.00

per cent, based on an allowed equity capital

structure of

per cent. An ROE of

9.95

per cent will be used for the calculation of the return on

investments for clauses. See below for further detail.

Fuel Recovery

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 a subsequent year.

On January 19, 2022, Tampa

Electric requested a mid-course adjustment to its fuel

and capacity charges

to recover an additional $

169

million USD, effective with April 2022 customer

bills, due to an increase in

fuel commodity and capacity costs. The FPSC is expected

to issue its decision in March 2022.

On July 19, 2021, Tampa

Electric requested a mid-course adjustment of $

million USD to its fuel and

capacity charges, effective with September 2021

customer bills, due to an increase in fuel commodity

and

capacity costs in 2021. On August 3, 2021, the FPSC

approved the request to recover the costs during

the months of September through December 2021.

Base rates

On August 6, 2021, Tampa

Electric filed with the FPSC a joint motion for approval of

a settlement

agreement (the “Settlement Agreement”) by Tampa

Electric and the intervenors in relation to its rate case

filed with the FPSC in April 2021. The Settlement Agreement

provides for a projected increase of $

191

million USD in rates annually,

effective with January 2022 bills. This increase

will consist 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 U.S. Treasury

Bond

yields exceed a specific threshold set on the date the

FPSC votes to approve the agreement. Under the

agreement, base rates will not further change from January

1, 2022 through December 31, 2024, unless

Tampa

Electric’s earned ROE were to fall below the

bottom of the range during that time. The Settlement

Agreement contains a provision whereby Tampa

Electric agrees to quantify the future impact

of a change

in tax rates on net operating income through a reduction

or increase in base revenues within 180 days of

when such tax change becomes law or its effective

date. 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 October 21, 2021, the FPSC approved the Settlement

Agreement and the final order,

reflecting

such approval, was issued in November 2021.

On April 9, 2019, Tampa

Electric reached a settlement agreement with consumer

parties regarding

eligible storm costs as a result of Hurricane Irma in 2017,

which was approved by the FPSC on May 21,

2019. As a result, Tampa

Electric refunded $

million USD to customers in January 2020, resulting in

minimal impact to the Consolidated Statements of Income.

Solar Base Rate Adjustments Included in Base Rates

As of December 31, 2021, Tampa

Electric has invested $

850

million USD in

600

MW of utility-scale solar

photovoltaic projects, which are recoverable through FPSC-approved

solar base rate adjustments

(“SoBRAs”). AFUDC is being 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.

The true-up filing for SoBRAs tranche 1 and 2 revenue

requirement estimates that were included in base

rates as of September 2018 and January 2019, respectively,

was submitted on April 30, 2020, and the

FPSC approved the amount on August 18, 2020. A $

million USD true-up was returned to customers in

2020. On October 12, 2021, the FPSC approved the true-up filing

for SoBRA tranche 3, included in base

rates as of January 2020. An estimated $

million true-up was returned to customers during

2021. The

true-up for SoBRA tranche 4 will be filed in early 2022.

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. Tampa

Electric submitted its storm protection plan with

the FPSC on April

10, 2020. On April 27, 2020, Tampa

Electric submitted a settlement agreement with

the FPSC which

specified a $

million USD base rate reduction for SPP program costs

previously recovered in base

rates beginning January 1, 2021. On June 9, 2020, the

FPSC approved this settlement agreement. On

August 3, 2020, Tampa

Electric submitted another settlement agreement to the

FPSC for approval,

including cost recovery of approximately $

million USD in proposed storm protection project costs

for

2020 and 2021. This cost recovery includes the $

million USD of costs removed from base rates. This

settlement agreement was approved on August 10,

2020 and Tampa

Electric’s cost recovery began in

January 2021. The current approved plan will apply for

the years 2020, 2021 and 2022, and

Tampa

Electric will file a new plan in April 2022 to determine cost

recovery in 2023, 2024, and 2025.

The June 9, 2020 settlement agreement approved by the

FPSC disclosed above also included approval

of Tampa

Electric’s petition to eliminate its $

million USD accumulated amortization reserve surplus

for

intangible software assets through a credit to amortization

expense in 2020.

Big Bend Modernization Project

Tampa

Electric expects to invest approximately $

850

million USD during 2018 through 2023 to modernize

the Big Bend Power Station,

of which approximately $

695

million USD has been invested through

December 31, 2021. The modernization project will repower

Big Bend Unit 1 with natural gas combined-

cycle technology and eliminate 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 operationa

perspectives.

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 depreciate 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 Settlement Agreement provides recovery

for the Big Bend Modernization project in two

phases. The first phase is 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.

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 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 2021 and 2020 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.

NSPI has a FAM, approved

by UARB which enables it to seek recovery of its fuel

costs from customers

through regularly scheduled fuel rate adjustments. Differences

between actual 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 years.

NSPI is currently operating under a

three

-year fuel stability plan which results in an average annual

overall rate increase of

1.5

per cent to recover fuel costs for the period of 2020 through

2022. These rates

include recovery of Maritime Link costs.

On January 27, 2022, NSPI filed a General Rate Application

(“GRA”) with the UARB. The GRA proposes

a rate stability plan for 2022 through 2024 which includes average

base rate increases of

2.9

per cent per

year and average fuel rate increases pursuant to the FAM

0.8

per cent per year on August 1, 2022,

January 1, 2023 and January 1, 2024. The proposed rates

would result in annualized incremental

revenue (base and fuel rates) increases of $

million in 2022 ($

million related to August 1, 2022

through December 31, 2022), $

million in 2023 and $

million in 2024. A decision by the UARB is

expected later this year.

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. The

UARB approved 2021 interim cost assessment recovery

payment to NSPML was $

172

million (2020 -

145

million) and as of December 31, 2021 $

139

million (2020 - $

135

million) has been paid.

The

approved interim cost assessment payments are subject to a holdback of up to $10 million pending UARB

agreement that benefits from the Maritime Link are realized for NSPI customers

. For 2021, NSPI has

recorded a $

million (2020 - $

million) holdback payable to NSPML and NSPML has deferred

collection of $

million in depreciation expense in 2021. On January 18,

2022, the UARB directed NSPI

to pay to NSPML

approximately $

million of the 2021 holdback.

As part of a

three

-year fuel stability plan, electricity rates have been

set to include the $

145

million

approved Maritime Link assessment for 2020 and 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.

In response to the delayed timing of energy delivery from the Muskrat Falls project, which is being

developed by Nalcor Energy, the approved Maritime Link interim assessment payment in 2019 reflected a

reduction in NSPML’s assessment, related to depreciation and amortization expenses. The UARB’s

decision to approve NSPI’s 2020 through 2022 fuel stability plan outlined the treatment of the reduced

2019 NSPML assessment of $52 million plus interest. NSPI refunded approximately $40 million plus

interest to customers, and the remaining $12 million plus interest will be returned to customers

subsequent to 2022.

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 NS Block delivery obligations commenced on August 15,

2021 and delivery will continue over the

years pursuant to the agreements. On August 9, 2021,

NSPML filed a final capital cost

application with the UARB seeking approval to recover

capital costs associated with the Maritime Link

and approval of NSPML’s

2022 assessment. In December 2021, NSPML obtained

an interim decision

from the UARB approving interim rates beginning January

1, 2022, until receipt of the UARB’s decision

on the application. On February 9, 2022, the UARB issued

its decision relating to the Maritime Link

Project, approving NSPML’s

requested rate base of approximately $

1.8

billion less costs that would not

otherwise have been recoverable if incurred by NSPI.

The UARB also approved approximately $

168

million of NSPML revenue requirement in 2022 subject

to a holdback of $

million per month beginning

April 1, 2022 and thereafter

to the end of the year. This

holdback is to be used to fund any replacement

energy costs incurred by NSPI due to a 10 per cent or

greater shortfall in contracted NS Block deliveries

each month and will otherwise be released to NSPML.

NSPML is required to provide the UARB with a

compliance filing by February 16, 2022 which will confirm the

impacts of this decision including the

amount of the unrecoverable items which are not expected

to exceed $

million (pre-tax).

Other Electric Utilities

The Barbados Light & Power Company Limited

BLPC is regulated by the Fair Trading

Commission (“FTC”),

an independent regulator, under

the Utilities

Regulation (Procedural) Rules 2003. 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. Following a general election called late in 2021

for January 19, 2022, the new licenses are

expected to take effect in 2022 on completion

of the legislative process. The Dispatch license will have

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 currently assessing the full impact of the

new

licenses on its business and working towards the successful

implementation of the licenses.

BLPC is regulated under a cost-of-service model, with

rates set to recover prudently incurred costs of

providing electricity service to customers and provide an

appropriate return to investors. BLPC’s

approved regulated return on rate base was

per cent for 2021 and 2020.

BLPC has a fuel pass-through mechanism which provides

the opportunity to recover all prudently

incurred fuel costs from customers in a timely manner.

The approved calculation of the fuel charge is

adjusted monthly and reported to the regulator.

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. A decision is expected from the FTC in the

second half of 2022.

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

relation to the hedging administrative costs, or any gains

and losses associated with the hedging

program. A decision is expected from the FTC in the first

half of 2022.

In December 2018, the Government of Barbados signed the

Income Tax

Amendment Act

into law. This

legislation, which was effective January 1, 2019,

created a new corporate income tax rate schedule and

eliminated certain tax credits. At the date of enactment, BLPC

was required to remeasure its deferred

income tax liability at the new lower corporate income tax

rate, resulting in recognition of an income tax

recovery of $

million USD of which $

million USD was deferred as a regulatory

liability, all of which

was recognized in earnings in Q1 2020.

Grand Bahama Power Company Limited

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. There is a fuel pass-

through mechanism and tariff review policy

with new rates submitted every three years. GBPC’s

approved

regulated return on rate base was

8.37

per cent for 2021 (2020 -

8.34

per cent).

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 becomes

effective April 1, 2022, allows for

an increase in revenues of $

3.5

million USD. The new rates include a regulatory ROE

12.84

per cent.

In 2017, as part of the recovery of costs incurred as a

result of Hurricane Matthew,

the GBPA approved

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. In

September 2021, GBPC filed an application for rate

review with the GBPA.

As part of its decision 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.

Dominica Electricity Services Ltd

Domlec is regulated by the Independent Regulatory Commission,

Dominica. On October 7, 2013, the

Independent Regulatory Commission, Dominica issued

a Transmission, Distribution & Supply

License

and a Generation License, both of which came into effect

on January 1, 2014, for a period of

years. Domlec’s approved allowable regulated return

on rate base was

per cent for 2021 and 2020.

Domlec has a fuel pass-through mechanism which provides

opportunity to recover substantially all

prudently incurred fuel costs in a timely manner.

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 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. PGS’s approved ROE range for

2020 was

9.25

per cent to

11.75

per cent, based on an allowed equity capital structure

54.7

per cent. An ROE of

10.75

per cent was used for the calculation of return on

investments for clauses.

PGS recovers the costs it pays for gas supply and

interstate transportation for system supply through its

purchased gas adjustment clause. 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.

The FPSC annually approves cost-recovery rates

for conservation costs and Cast Iron/Bare Steel Pipe

Replacement costs, including a return on capital invested

incurred in developing and implementing

energy conservation programs. The Cast Iron/Bare Steel

Pipe Replacement clause is to recover the cost

of accelerating the replacement of cast iron and bare

steel distribution lines in the PGS system. The

FPSC approved a replacement program of approximately

per cent, or

800

kilometres, of the PGS

system at a cost of approximately $

million USD over a

-year period beginning in 2013.

In February

2017, the FPSC approved an amendment to the cast iron

bare steel rider to include certain plastic

materials and pipe deemed obsolete by Pipeline and Hazardous

Materials Safety Administration, totaling

approximately

880

kilometres. PGS estimates that the majority of cast

iron and bare steel pipe will be

removed from its system by the end of 2022, with the replacement

of obsolete plastic pipe continuing until

2028 under the rider.

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. PGS has not reversed any of this

accumulated depreciation to date. 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

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 2021 was

9.375

per cent on an allowed equity capital structure of

per cent.

The approved ROE for 2020 was

9.10

per cent on an allowed capital structure of

per cent.

NMGC recovers gas supply costs through a purchased

gas adjustment clause (“PGAC”). This clause

recovers NMGC’s actual costs for purchased gas, gas

storage services, interstate pipeline capacity,

and

other related items associated with the purchase, transmi

ssion, 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.

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.

On June 15, 2021, the NMPRC approved the recovery

over a period of

months beginning July 1,

2021. For more information, refer to the “NMGC Winter

Event Gas Cost Recovery” section above.

On December 16, 2020, the NMPRC approved a settlement

agreement for new rates that became

effective on January 1, 2021. The new rates reflect

the recovery of capital investment in pipelines and

related infrastructure and resulted in an increase in revenue

of approximately $

million USD annually.

On December 13, 2021, NMGC filed a rate case with

the NMPRC for new rates to become effective

January 2023. NMGC requested a $

million increase in annual base revenues primarily

as a result of

increased operating costs and capital investments in pipelines

and related infrastructure. A decision from

the NMPRC is expected by the end of 2022.

Brunswick Pipeline

Brunswick Pipeline is a

145

-kilometre pipeline delivering natural gas from the Canaport™

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

Canada. The agreement provides for a predetermined

toll increase in the fifth and fifteenth year of the

contract. The pipeline is considered

a Group II pipeline regulated by the Canada Energy Regulator

(“CER”). The CER Gas Transportation Tariff

is filed by Brunswick Pipeline in compliance with the

requirements of the

CER Act

and sets forth the terms and conditions of the transportation

rendered by

Brunswick Pipeline.

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 Canadian dollars

2021

2020

2021

2020

2021

LIL

(1)

682

629

37.4

NSPML

533

547

100.0

M&NP

(2)

123

129

12.9

Lucelec

(2)

19.5

Bear Swamp

(3)

50.0

1,382

1,346

143

149

(1) Emera indirectly owns

100

per cent of the Class B units, which comprises

24.9

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 to

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 in

these entities using the equity method.

(3) The investment balance in Bear Swamp is

in a credit position primarily as a result

of a $

179

million distribution received in 2015.

Bear Swamp's credit investment balance of $

104

million (2020 – $

118

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 Canadian dollars

2021

2020

Balance Sheets

Current assets

Property, plant and equipment

1,587

1,629

Regulatory assets

247

210

Non-current assets

Total

assets

1,890

1,928

Current liabilities

Long-term debt

(1)

1,189

1,228

Non-current liabilities

118

Equity

533

547

Total

liabilities and equity

1,890

1,928

(1) The project debt has been guaranteed

by the Government of Canada.

OTHER INCOME, NET

Other income, net consisted of the following:

For the

Year ended December 31

millions of Canadian dollars

2021

2020

Allowance for equity funds used during construction

Gain on sale of Emera Maine, net of transaction costs

(1)

585

TECO Guatemala Holdings award

(2)

Other

708

(1) Refer to note 4 for further detail related to

the gain on sale of Emera Maine.

(2) 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 Canadian dollars

2021

2020

Income before provision for income taxes

555

1,325

Statutory income tax rate

29.0%

29.5%

Income taxes, at statutory income tax rate

161

391

Additional impact from the sale of Emera Maine

102

Deferred income taxes on regulated income recorded as regulatory assets and

regulatory liabilities

(62)

(48)

Foreign tax rate variance

(42)

(45)

Amortization of deferred income tax regulatory liabilities

(33)

(44)

Tax

effect of equity earnings

(16)

(15)

Tax

credits

(13)

(12)

Revaluation of deferred income taxes due to change in Nova Scotia tax rate

Other

(1)

Income tax (recovery) expense

(6)

341

Effective income tax rate

(1%)

26%

The change in the effective income tax rate was

primarily due to decreased income before provision

for

income taxes and the additional impact from the sale

of Emera Maine in 2020.

On March 10, 2020, Bill 243 of the Nova Scotia Financial

Measures (2020) Act was enacted, which

included a reduction in the Nova Scotia provincial corporate

income tax rate. As a result, the Company's

combined Canadian federal and provincial statutory income tax

rate was reduced from

per cent to

29.5

per cent for 2020, and further reduced to

per cent for 2021 onward.

As a result of the change in tax rate in 2020, the Company

recorded a reduction of $

million to its net

deferred income tax liabilities and an offsetting

reduction to its net deferred income tax regulatory

asset,

as the benefit of lower net deferred income tax liabilities

is expected to be returned to customers in future

years. The Company also recognized a $

million income tax expense as a result of the revaluation

certain net deferred income tax assets.

On March 27, 2020, the United States Coronavirus Aid,

Relief, and Economic Security (CARES) Act (“the

CARES Act”) was signed into law.

Under the CARES Act, companies can accelerate

the refund of

alternative minimum tax (“AMT”) credit carryforwards.

As a result, the Company received the balance of

its $

145

million of refundable AMT credit carryforwards

in 2020. The Company has not had any other

material impacts from the CARES Act.

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 Canadian dollars

2021

2020

Current income taxes

Canada

United States

(58)

Deferred income taxes

Canada

(33)

United States

118

426

Other

(9)

Investment tax credits

United States

(11)

(10)

Operating loss carryforwards

Canada

(64)

(46)

United States

(49)

Income tax (recovery) expense

(6)

341

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 Canadian dollars

2021

2020

Canada

244

176

United States

289

1,142

Other

Income before provision for income taxes

555

1,325

The deferred income tax assets and liabilities presented in

the Consolidated Balance Sheets as at

December 31 consisted of the following:

millions of Canadian dollars

2021

2020

Deferred income tax assets:

Tax

loss carryforwards

873

724

Tax

credit carryforwards

375

319

Derivative instruments

188

108

Regulatory liabilities - cost of removal

170

184

Other

434

375

Total

deferred income tax assets before valuation allowance

2,040

1,710

Valuation allowance

(256)

(202)

Total

deferred income tax assets after valuation allowance

1,784

1,508

Deferred income tax (liabilities):

Property, plant and equipment

(2,622)

(2,450)

Derivative instruments

(197)

(93)

Other

(538)

(385)

Total

deferred income tax liabilities

(3,357)

(2,928)

Consolidated Balance Sheets presentation:

Long-term deferred income tax assets

295

209

Long-term deferred income tax liabilities

(1,868)

(1,629)

Net deferred income tax liabilities

(1,573)

(1,420)

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 investments. A valuation allowance

of $

256

million has been recorded as at December 31, 2021 (2020

- $

202

million) related to the loss

carryforwards and investments.

The Company intends to indefinitely reinvest earnings

from certain foreign operations. Accordingly,

2.9

billion as at December 31, 2021 (2020 - $

2.7

billion) in cumulative temporary differences

for which

deferred taxes might otherwise be required, have not

been recognized. It is impractical to estimate the

amount of income and withholding tax that might be payable

if a reversal of temporary differences

occurred.

Emera’s net operating loss (“NOL”), capital loss

and tax credit carryforwards and their expiration periods

as at December 31, 2021 consisted of the following:

Subject to

Tax

Valuation

Net Tax

Expiration

millions of Canadian dollars

Carryforwards

Allowance

Carryforwards

Period

Canada

NOL

1,776

(791)

985

2026 - 2041

Capital loss

(75)

Indefinite

United States

Federal NOL

1,521

2032 - Indefinite

State NOL

817

2032 - Indefinite

Tax credit

375

2025 - 2041

Other

NOL

(38)

2022 - 2028

The following table provides details of the change in unrecognized

tax benefits for the years ended

December 31 as follows:

millions of Canadian dollars

2021

2020

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

(1)

(2)

Decreases due to settlement with tax authorities

(6)

Balance, December 31

The total amount of unrecognized tax benefits as at December

31, 2021 was $

million (2020 - $

million), which would affect the effective

tax rate if recognized. The total amount of accrued interest

with

respect to unrecognized tax benefits was $

million (2020 - $

million) with nil interest expense

recognized in the Consolidated Statements of Income

(2020 - $

million).

penalties have been

accrued. The balance of unrecognized tax benefits could

change in the next 12 months as a result of

resolving Canada Revenue Agency (“CRA”) and Internal Revenue

Service audits. A reasonable estimate

of any change cannot be made at this time.

NSPI and the CRA are currently in a dispute with respect

to the timing of certain tax deductions for

NSPI’s 2006 through 2010 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 $

million, including interest. NSPI has prepaid $

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

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

with the Tax

Court of Canada with respect to its

dispute. 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 excess, if any,

owing to 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 Appeal process is not

determinable at this time.

Emera files a Canadian federal income tax return, which includes

its Nova Scotia and New Brunswick

provincial income tax. Emera’s subsidiaries file

Canadian, US, Barbados, St. Lucia and Dominica income

tax returns. As at December 31, 2021, 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.

2021

2020

Issued and outstanding:

millions

of shares

millions of

Canadian

dollars

millions of

Canadian

dollars

Balance, December 31, 2020

251.43

6,705

242.48

6,216

Issuance of common stock

(1)(2)

4.99

284

4.54

251

Issued under Purchase Plans at market rate

4.32

239

3.99

219

Discount on shares purchased under Dividend Reinvestment Plan

(4)

Options exercised under senior management share option plan

0.33

0.42

Employee Share Purchase Plan

Balance, December 31, 2021

261.07

7,242

251.43

6,705

(1) As at December 31, 2020, a total of

4,544,025

common shares were issued under Emera's at-the-market

program "(ATM program)"

at an average price of $

56.04

per share for gross proceeds of $

255

million ($

251

million net of issuance costs).

(2) For the year ended December 31, 2021,

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).

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, 2021, an aggregate gross sales limit of

457

million remains available for issuance under the ATM

program.

As at December 31, 2021, the following common shares

were reserved for issuance:

6.2

million (2020 –

3.5

million) under the senior management stock option

plan,

3.1

million (2020 –

3.5

million) under the

employee common share purchase plan and

14.2

million (2020 –

5.1

million) under the dividend

reinvestment plan (“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, 2021,

Emera is in compliance with this requirement.

12.

EARNINGS PER SHARE

Basic earnings per share (“EPS”) is determined by dividing

net income attributable to common

shareholders by the weighted average number of common shares

and DSUs outstanding during the

period. Diluted EPS is computed by dividing net income

attributable to common shareholders by the

weighted average number of common shares and DSUs

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 dividend reinvestment plan.

The following table reconciles the computation of basic

and diluted earnings per share:

For the

Year ended December 31

millions of Canadian dollars (except per share amounts)

2021

2020

Numerator

Net income attributable to common shareholders

510.5

937.6

Diluted numerator

510.5

937.6

Denominator

Weighted average shares of common stock outstanding

255.9

246.5

Weighted average deferred share units outstanding

1.3

Weighted average shares of common stock outstanding – basic

257.2

247.8

Stock-based compensation

0.4

Weighted average shares of common stock outstanding – diluted

257.6

248.2

Earnings per common share

Basic

1.98

3.78

Diluted

1.98

3.78

13.

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The components of accumulated other comprehensive income

are as follows:

millions of Canadian dollars

Unrealized

(loss) gain on

translation of

self-sustaining

foreign

operations

Net change in

net investment

hedges

(Losses)

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, 2021

Balance, January 1, 2021

(1)

(161)

(79)

Other comprehensive

income (loss) before

reclassifications

(42)

(19)

Amounts reclassified from

accumulated other

comprehensive income

(loss)

(1)

124

123

Net current period other

comprehensive income

(loss)

(42)

124

104

Balance, December 31,

2021

(1)

(37)

For the year ended December 31, 2020

Balance, January 1, 2020

253

(1)

(160)

Other comprehensive

income (loss) before

reclassifications

(201)

(175)

Amounts reclassified from

accumulated other

comprehensive income

(loss)

(1)

Net current period other

comprehensive income

(loss)

(201)

(1)

(174)

Balance, December 31,

2020

(1)

(161)

(79)

The reclassifications out of accumulated other comprehensive

income (loss) are as follows:

For the

Year ended December 31

millions of Canadian dollars

2021

2020

Affected line item in the Consolidated Financial Statements

(Gains) Losses on derivatives recognized as cash flow hedges

Foreign exchange forwards

Operating revenue – regulated

Interest rate hedge

Interest expense, net

(1)

Total

(1)

Net change in unrecognized pension and post-retirement benefit costs

Actuarial losses (gains)

Other income, net

Past service costs (gains)

Other income, net

(1)

Amounts reclassified into obligations

Pension and post-retirement benefits

102

(16)

Total

before tax

126

(2)

Income tax (expense) recovery

(2)

Total

net of tax

124

(1)

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

123

14.

INVENTORY

As at

December 31

millions of Canadian dollars

2021

2020

Fuel

255

199

Materials

283

254

538

453

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 Canadian dollars

2021

2020

2021

2020

Cash flow hedges

Interest rate hedge

Regulatory deferral

Commodity swaps and forwards

Coal purchases

Power purchases

Natural gas purchases and sales

Heavy fuel oil purchases

Foreign exchange forwards

Physical natural gas purchases and sales

241

HFT derivatives

Power swaps and physical contracts

Natural gas swaps, futures, forwards, physical

contracts

208

139

818

346

241

152

850

359

Other derivatives

Equity derivatives

Foreign exchange forwards

Total

gross current derivatives

493

184

874

424

Impact of master netting agreements with intent to

settle net or simultaneously

(192)

(86)

(192)

(86)

Total derivatives

301

682

338

Current

195

533

251

Long-term

106

149

Total derivatives

301

682

338

Derivative assets and liabilities are classified as current

or long-term based upon the maturities of the

underlying contracts.

Details of master netting agreements, shown net on the Consolidated

Balance Sheets, are summarized in

the following table:

Derivative Assets

Derivative Liabilities

As at

December 31

millions of Canadian dollars

2021

2020

2021

2020

Regulatory deferral

HFT derivatives

188

Total

impact of master netting agreements with

intent to settle net or simultaneously

192

Cash Flow Hedges

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

of $

million USD that will be amortized

through interest expense over

10 years

. As of December 31, 2021, there were

outstanding cash flow

hedges.

The amounts related to cash flow hedges recorded in income

and AOCI consisted of the following:

For the

Year ended December 31

millions of Canadian dollars

2021

2020

Interest

Foreign

rate hedge

exchange forwards

Realized loss in operating revenue – regulated

(2)

Realized gain in interest expense, net

Total

gains (losses) in net income

(2)

As at

December 31

millions of Canadian dollars

2021

2020

Interest

rate hedge

Total

unrealized gain in AOCI – effective portion, net of tax

The Company expects $

million of unrealized gains currently in AOCI to be reclassified

into net income

within the next 12 months.

Regulatory Deferral

The Company has recorded the following changes in realized

and unrealized gains (losses) with respect

to derivatives receiving regulatory deferral:

For the

Year ended December 31

millions of Canadian dollars

2021

Natural gas

Commodity

swaps and

forwards

Foreign

exchange

forwards

Unrealized gain (loss) in regulatory assets

(7)

Unrealized gain (loss) in regulatory liabilities

218

(3)

Realized (gain) in regulatory liabilities

(3)

Realized (gain) loss in inventory

(1)

(8)

Realized (gain) loss in regulated fuel for generation and purchased

power

(2)

(39)

Total

change derivative instruments

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.

For the

Year ended December 31

millions of Canadian dollars

2020

Natural gas

Commodity

swaps and

forwards

Foreign

exchange

forwards

Unrealized gain (loss) in regulatory assets

(36)

(11)

Unrealized gain (loss) in regulatory liabilities

Realized gain (loss) in regulatory assets

Realized (gain) loss in regulatory liabilities

Realized (gain) loss in inventory

(1)

(2)

Realized (gain) loss in regulated fuel for generation and purchased

power

(2)

(3)

Total

change derivative instruments

(13)

(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.

Commodity Swaps and Forwards

As at December 31, 2021, the Company had the following

notional volumes of commodity swaps and

forward contracts designated for regulatory deferral that are

expected to settle as outlined below:

2022

2023-2024

millions

Purchases

Natural Gas (Mmbtu)

Power (MWh)

Foreign Exchange Swaps and Forwards

As at December 31, 2021, the Company had the following

notional volumes of foreign exchange swaps

and forward contracts designated for regulated deferral that

are expected to settle as outlined below:

2022

2023-2024

Foreign exchange contracts (millions of US dollars)

170

150

Weighted average rate

1.3047

1.2413

% of USD requirements

65%

29%

The Company reassesses foreign exchange forecasted periodically

and will enter into additional hedges

or unwind existing hedges, as required.

Held-for-Trading Derivatives

In the ordinary course of its business, Emera enters into

physical contracts for the purchase and sale of

natural gas, as well as power and natural gas swaps,

forwards and futures, to economically hedge those

physical contracts. These derivatives are all considered

HFT.

The Company has recognized the following realized and

unrealized gains (losses) with respect to HFT

derivatives:

For the

Year ended December 31

millions of Canadian dollars

2021

2020

Power swaps and physical contracts in non-regulated operating revenues

(1)

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

operating revenues

(142)

205

Power swaps, forwards, futures and physical contracts in non-regulated fuel for

generation and purchased power

(4)

(138)

200

As at December 31, 2021, the Company had the following

notional volumes of outstanding HFT

derivatives that are expected to settle as outlined below:

millions

2022

2023

2024

2025

2026

Natural gas purchases (Mmbtu)

308

Natural gas sales (Mmbtu)

335

103

Power purchases (MWh)

Power sales (MWh)

Other Derivatives

As at December 31, 2021, the Company had equity derivatives

in place to manage the cash flow risk

associated with forecasted future cash settlements of deferred

compensation obligations and foreign

exchange forwards in place to manage cash flow risk

associated with forecasted USD cash inflows.

The

equity derivative hedges the return on

2.8

million shares and extends until December of 2022. The

foreign

exchange forwards have a combined notional amount

of $

million USD and expire throughout 2022 and

2023.

For the

Year ended December 31

millions of Canadian dollars

2021

2020

Foreign

Exchange

Equity

Exchange

Equity

Forwards

Derivatives

Forwards

Derivatives

Unrealized gain (loss) in operating, maintenance and general

(1)

Unrealized gain (loss) in other income (expense), net

(15)

Realized gain (loss) in operating, maintenance and general

(3)

Realized gain (loss) in other income (expense)

(2)

Total

gains (losses) in net income

(4)

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, 2021, the maximum exposure the

Company has to credit risk is $

1.3

billion (2020 -

805

million), 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, foreign exchange

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, 2021 was $

341

million (2020 - $

251

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 (“ISDA”), North American

Energy Standards Board agreements

(“NAESB”) and, or Edison Electric Institute agreements.

The Company believes that entering into such

agreements offers protection by creating contractual rights

relating to creditworthiness, collateral, non-

performance and

default.

As at December 31, 2021, the Company had $

114

million (2020 - $

123

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 $

million (2020 - $

101

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, 2021

December 31, 2020

millions of

Canadian

dollars

% of total

exposure

millions of

Canadian

dollars

% of total

exposure

Receivables, net

Regulated utilities

Residential

384

24%

341

32%

Commercial

167

10%

143

14%

Industrial

Other

696

43%

629

60%

Trading group

Credit rating of A- or above

Credit rating of BBB- to BBB+

107

Not rated

132

305

19%

170

16%

Other accounts receivable

329

20%

159

15%

1,330

82%

958

91%

Derivative Instruments

(current and long-term)

Credit rating of A- or above

155

Credit rating of BBB- to BBB+

Not rated

124

301

18%

1,631

100%

1,056

100%

Cash Collateral

The Company’s cash collateral positions consisted

of the following:

As at

December 31

millions of Canadian dollars

2021

2020

Cash collateral provided to others

212

Cash collateral received from others

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, 2021, the total fair value of derivatives

in a liability position was $

682

million

(December 31, 2020

–

338

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, 2021

millions of Canadian dollars

Level 1

Level 2

Level 3

Total

Assets

Regulatory deferral

Commodity swaps and forwards

Coal purchases

Power purchases

Natural gas purchases and sales

Heavy fuel oil purchases

Foreign exchange 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

Power purchases

Natural gas purchases and sales

Foreign exchange 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)

As at

December 31, 2020

millions of Canadian dollars

Level 1

Level 2

Level 3

Total

Assets

Cash flow hedges

Interest rate hedge

Regulatory deferral

Commodity swaps and forwards

Power purchases

Natural gas purchases and sales

Heavy fuel oil purchases

HFT derivatives

Power swaps and physical contracts

Natural gas swaps, futures, forwards, physical

contracts and related transportation

Other derivatives

Foreign exchange forwards

Total assets

Liabilities

Regulatory deferral

Commodity swaps and forwards

Coal purchases

Power purchases

Heavy fuel oil purchases

Natural gas purchases and sales

Foreign exchange forwards

HFT derivatives

Power swaps and physical contracts

Natural gas swaps, futures, forwards and physical

contracts

257

268

258

275

Other derivatives

Equity derivatives

Total liabilities

258

338

Net assets (liabilities)

(26)

(244)

(240)

The change in the fair value of the Level 3 financial assets

for the year ended December 31, 2021 was as

follows:

Regulatory Deferral

HFT Derivatives

millions of Canadian dollars

Physical natural

gas purchases and

sales

Power

Natural

gas

Total

Balance, January 1, 2021

Unrealized gains included in regulatory assets or

liabilities

Total

realized and unrealized gains included in

non-regulated operating revenues

Balance, December 31, 2021

104

The change in the fair value of the Level 3 financial liabilities for

the year ended December 31, 2021 was

as follows:

HFT Derivatives

millions of Canadian dollars

Power

Natural

gas

Total

Balance, January 1, 2021

257

258

Total

realized and unrealized losses included in non-regulated

operating revenues

258

260

Balance, December 31, 2021

515

518

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; 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.

Significant increases (decreases) in any of these

inputs in isolation would result in a significantly lower (higher)

fair value measurement.

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:

As at

December 31, 2021

millions of Canadian dollars

Fair

Value

Valuation

Technique

Unobservable Input

Range

Weighted

average

(1)

Assets

Regulatory deferral – Physical

Modelled pricing

Third-party pricing

4.51

- $

26.09

9.74

natural gas purchases and sales

Probability of default

2.52

% -

4.4

3.31

Discount rate

0.01

% -

1.6

0.48

HFT derivatives – Power swaps

Modelled pricing

Third-party pricing

37.05

- $

213.00

93.60

and physical contracts

Probability of default

0.01

% -

2.52

0.45

Discount rate

0.00

% -

1.86

0.19

HFT derivatives

–

Modelled pricing

Third-party pricing

2.18

- $

20.42

3.75

Natural gas swaps, futures,

Probability of default

0.01

% -

7.38

0.13

forwards and physical contracts

Discount rate

0.00

% -

11.98

0.37

(8)

Modelled pricing

Third-party pricing

2.83

- $

20.86

10.85

Basis adjustment

0.00

0.44

0.42

Probability of default

0.01

% -

4.17

0.46

Discount rate

0.00

% -

1.73

0.21

Total assets

104

Liabilities

HFT derivatives

–

Modelled pricing

Third-party pricing

37.8

0 - $

145.8

111.15

Power swaps and

Own credit risk

0.01

% -

1.48

0.12

physical contracts

Discount rate

0.01

% -

1.86

0.31

Modelled pricing

Third-party pricing

37.46

- $

126.75

95.02

Correlation factor

100% - 100%

100%

Own credit risk

0.01

% -

11.16

0.07

Discount rate

0.01

% -

1.86

0.21

HFT derivatives

–

458

Modelled pricing

Third-party pricing

1.9

0 - $

20.42

9.12

Natural gas swaps, futures,

Own credit risk

0.01

% -

7.38

0.08

forwards and physical contracts

Discount rate

0.00

% -

14.59

1.54

Modelled pricing

Third-party pricing

2.83

- $

21.53

12.03

Basis adjustment

0.00

- $

1.11

0.28

Own credit risk

0.01

% -

0.49

0.02

Discount rate

0.00

% -

1.73

0.13

Total liabilities

518

Net liabilities

(414)

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

As at

December 31, 2020

millions of Canadian dollars

Fair

Value

Valuation

Technique

Unobservable Input

Range

Weighted

average

(1)

Assets

HFT derivatives

–

Modelled pricing

Third-party pricing

$20.50 - $62.45

31.14

Power swaps and

Probability of default

0.02

% -

9.74

2.52

physical contracts

Discount rate

0.01

% -

0.73

0.25

Modelled pricing

Third-party pricing

$25.70 - $36.05

29.53

Probability of default

0.36

% -

0.85

0.6

Discount rate

0.06

% -

0.41

0.28

Correlation factor

100

% -

100

HFT derivatives

–

Modelled pricing

Third-party pricing

$1.66 - $6.22

2.52

Natural gas swaps, futures,

Probability of default

0.02

% -

2.52

0.4

forwards, and physical contracts

Discount rate

0.00

% -

10.36

0.75

(6)

Modelled pricing

Third-party pricing

$1.82 - $6.44

4.66

Basis adjustment

$0.00 - $1.33

0.44

Probability of default

0.02

% -

12.58

1.95

Discount rate

0.00

% -

0.67

0.13

Total assets

Liabilities

HFT derivatives

–

Modelled pricing

Third-party pricing

1.13

- $

62.45

36.90

Power swaps and physical

contracts

Own credit risk

0.02

% -

6.85

2.02

Discount rate

0.01

% -

0.73

0.34

Modelled pricing

Third-party pricing

37.25

- $

62.45

55.00

Own credit risk

0.36

% -

1.28

0.83

Discount rate

0.01

% -

0.40

0.31

Correlation factor

100

% -

100

100%

HFT derivatives

–

226

Modelled pricing

Third-party pricing

1.44

- $

6.57

3.68

Natural gas swaps, futures,

Own credit risk

0.02

% -

2.52

0.10

forwards and physical contracts

Discount rate

0.00

% -

8.79

0.43

Modelled pricing

Third-party pricing

1.54

- $

8.44

4.69

Basis adjustment

0.00

- $

1.33

0.87

Own credit risk

0.03

% -

12.58

0.10

Discount rate

0.00

% -

0.67

0.16

Total liabilities

258

Net assets (liabilities)

(244)

'(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 Canadian dollars

Amount

Fair Value

Level 1

Level 2

Level 3

Total

December 31, 2021

14,658

16,775

16,308

467

16,775

December 31, 2020

13,721

16,487

16,020

467

16,487

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, 2021, the fair value of the Hybrid

Notes was $

1.7

billion (2020 – $

1.8

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

million was recorded

in OCI for the year ended December 31, 2021 (2020 –

million).

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 follow

●

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

149

million for the year ended December 31, 2021 (2020 - $

139

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, 2021 (2020

- $

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, 2021 and at December 31, 2020.

18.

RECEIVABLES AND OTHER CURRENT ASSETS

Receivables and other current assets consisted of the

following:

As at

December 31

millions of Canadian dollars

2021

2020

Customer accounts receivable – billed

767

570

Customer accounts receivable – unbilled

318

286

Allowance for credit losses

(21)

(22)

Capitalized transportation capacity

(1)

316

200

Income tax receivable

Prepaid expenses

Other

280

138

1,733

1,233

(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.

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 64 years, some of which include options to

extend the leases for up to 64 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 Canadian dollars

Classification

2021

2020

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 $

150

million for the year ended December 31, 2021 (2020

– $

160

million), of which $

142

million (2020 – $

149

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 Canadian dollars

2022

2023

2024

2025

2026

Thereafter

Total

Minimum lease payments

112

135

Less imputed interest

(73)

Total

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

Year ended December

For the

2021

2020

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

Operating cash flows for operating leases (millions of Canadian dollars)

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

Operating leases (millions of Canadian dollars)

Weighted average remaining lease term (years)

Weighted average discount rate-

operating leases

3.98%

3.96%

Lessor

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

Pipeline, compressed natural gas (“CNG”) stations and heat pumps.

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 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 at any time after 2021 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.

Net investment in direct finance and sales-type leases

consist of the following:

As at

December 31

millions of Canadian dollars

2021

2020

Total

minimum lease payment to be received

947

1,018

Less: amounts representing estimated executory costs

(165)

(179)

Minimum lease payments receivable

782

839

Estimated residual value of leased property (unguaranteed)

183

Less: unearned finance lease income

(443)

(487)

Net investment in direct finance and sales-type leases

522

535

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

Net investment in sales-type leases - long-term (included in "Other long-term

assets")

Net Investment in direct finance leases - long-term

462

475

As at December 31, 2021, future minimum lease payments

to be received for each of the next five years

and in aggregate thereafter are as follows:

millions of Canadian dollars

2022

2023

2024

2025

2026

Thereafter

Total

Minimum lease payments to be

received

555

947

Less: executory costs

(165)

Total

782

20.

PROPERTY,

PLANT AND EQUIPMENT

Property, plant and

equipment consisted of the following regulated and non-regulated

assets:

As at

December 31

millions of Canadian dollars

Estimated useful life

2021

2020

Generation

131

11,173

11,474

Transmission

2,532

2,414

Distribution

6,305

5,997

Gas transmission and distribution

4,385

3,879

General plant and other

(1)

2,473

2,127

Total

cost

26,868

25,891

Less: Accumulated depreciation

(1)

(8,739)

(8,714)

18,129

17,177

Construction work in progress

(1)

2,224

2,358

Net book value

20,353

19,535

(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, 2021, SeaCoast’s

share of plant in service was $

million (2020 - $

million), and accumulated

depreciation of $

million (2020 - nil). 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, Dominica and Grand Bahama Island.

On March 24, 2020, Emera sold

Emera Maine, refer to note 4 for further detail.

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 Canadian dollars

2021

2020

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

2,759

339

2,822

353

Service cost

Plan participant contributions

Interest cost

Benefits paid

(160)

(27)

(135)

(27)

Actuarial gains (losses)

(89)

(10)

189

Settlements and curtailments

(229)

(52)

Foreign currency translation adjustment

(2)

(1)

(25)

(7)

Balance, December 31

2,624

318

2,759

339

Change in plan assets

Balance, January 1

2,605

2,593

Employer contributions

Plan participant contributions

Benefits paid

(160)

(27)

(135)

(27)

Actual return on assets, net of expenses

214

310

Settlements and curtailments

(191)

(7)

Foreign currency translation adjustment

(5)

(1)

(20)

(1)

Balance, December 31

2,702

2,605

Funded status, end of year

(267)

(154)

(287)

The actuarial gains recognized in the period are primarily

due to gains associated with changes in the

discount rate and demographic assumption changes. This was

partially offset by losses associated with

changes in inflation and compensation-related assumptions.

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 Canadian dollars

2021

2020

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

PBO/APBO

140

290

2,736

308

Fair value of plan assets

2,568

Funded status

(105)

(290)

(168)

(308)

Plans with Accumulated Benefit Obligation (“ABO”)

in Excess of Plan Assets

The ABO for the defined benefit pension plans was $

2,507

million as at December 31, 2021 (2020 –

2,639

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 Canadian dollars

2021

2020

Defined benefit

pension plans

Defined benefit

pension plans

ABO

133

1,519

Fair value of plan assets

1,419

Funded status

(98)

(100)

Balance Sheet

The amounts recognized in the Consolidated Balance Sheets

consisted of the following:

As at

December 31

millions of Canadian dollars

2021

2020

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Other current liabilities

(7)

(20)

(4)

(19)

Long-term liabilities

(100)

(270)

(163)

(290)

Other long-term assets

185

Amount included in deferred income tax

(8)

(4)

(1)

AOCI and regulatory assets, net of tax

230

443

107

Net amount recognized

300

(176)

285

(183)

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 Canadian dollars

Defined Benefit Pension Plans

Balance, January 1, 2021

279

160

Amortized in current period

(24)

(21)

Current year addition to AOCI or regulatory assets

(61)

(109)

Change in foreign exchange rate

(2)

Balance, December 31, 2021

192

Non-pension benefits plans

Balance, January 1, 2021

110

(4)

Amortized in current period

(2)

(3)

Current year addition to AOCI or regulatory assets

(16)

Change in foreign exchange rate

(1)

Balance, December 31, 2021

2021

2020

millions of Canadian dollars

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Actuarial losses (gains)

160

(4)

Regulatory assets

192

279

110

Total

AOCI and regulatory assets before

deferred income taxes

222

439

106

Amount included in deferred income tax

assets

(1)

Net amount in AOCI and regulatory assets

230

443

107

Benefit Cost Components

Emera's net periodic benefit cost included the following:

As at

Year ended December 31

millions of Canadian dollars

2021

2020

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

(132)

(1)

(141)

(1)

Current year amortization of:

Actuarial losses (gains)

Past service costs (gains)

(1)

Regulatory assets (liability)

Total

The expected return on plan assets is determined based on

the market-related value of plan assets of

2,151

million as at January 1, 2021 (2020 – $

2,476

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

12%

22%

Non-Canadian

30%

55%

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 Canadian dollars

NAV

Level 1

Level 2

Total

Percentage

December 31, 2021

Cash and cash equivalents

Net in-transits

(84)

(3)

Equity Securities:

Canadian equity

US 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

December 31, 2020

Cash and cash equivalents

Net in-transits

(99)

(4)

Equity securities:

Canadian equity

154

US equity

380

Other equity

243

Fixed Income securities:

Government

119

Corporate

141

Other

Mutual funds

Other

(3)

(4)

(7)

Open-ended investments

measured at NAV

(1)

801

Common collective trusts

measured at NAV

(2)

704

Total

1,505

841

259

2,605

100

(1) NAV investments are open-ended registered and non-registered mutual funds,

collective investment trusts, or pooled funds.

NAV’s are calculated daily 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, 2021 and 2020, the assets related

to the pension funds and post-retirement benefit

plans do 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 Canadian dollars

Defined benefit

pension plans

Non-pension

benefit plans

Expected employer contributions

2022

Expected benefit payments

2022

153

2023

162

2024

162

2025

165

2026

169

2027 – 2031

872

104

Assumptions

The following table shows the assumptions that have been

used in accounting for defined benefit

pension and other post-retirement benefit plans:

2021

2020

(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

3.05

2.81

2.49

2.48

Discount rate - future service

3.18

2.92

2.64

2.51

Rate of compensation increase

3.31

3.29

2.89

3.04

Health care trend

- initial (next year)

5.09

5.64

- ultimate

3.77

4.35

- year ultimate reached

2042

2038

Benefit cost for year ended December 31:

Discount rate - past service

2.49

2.48

3.17

3.28

Discount rate - future service

2.64

2.51

3.21

3.28

Expected long-term return on plan assets

5.86

6.29

3.25

Rate of compensation increase

2.89

3.04

3.34

3.70

Health care trend

- initial (current year)

5.64

5.91

- ultimate

4.35

4.37

- year ultimate reached

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, 2021 was

million (2020 – $

million).

22.

GOODWILL

The change in goodwill for the year ended December 31

is due to the following:

millions of Canadian dollars

2021

2020

Balance, January 1

5,720

5,835

Change in foreign exchange rate

(24)

(115)

Balance, December 31

5,696

5,720

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, 2021, primarily relates to TECO Energy and

GBPC. Emera’s reporting units with goodwill

are Tampa

Electric, PGS, NMGC, and GBPC.

In 2021, Emera performed a qualitative impairment assessment

for Tampa

Electric, PGS and NMGC,

concluding that the fair value of the reporting units exceeded

their respective carrying amounts, and as

such, no quantitative assessments were performed and no

impairment charges were recognized.

Goodwill on Emera’s Consolidated Balance Sheets

at December 31, 2021, included $

million (2020 –

million) related to GBPC. In 2021, the Company performed

a quantitative impairment assessment

using a discounted cash flow analysis. This assessment estimated

that the fair value of the reporting unit

exceeded its carrying value, including goodwill, by approximately

per cent. Adverse changes in

assumptions used could result in a future impairment.

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 Canadian dollars

2021

Weighted

average

interest rate

2020

Weighted

average

interest rate

Tampa Electric Company ("TEC")

Advances on term, revolving and accounts receivable facilities

945

0.58

987

0.89

Emera

Non-revolving term facility

400

0.96

400

0.94

Bank indebtedness

TECO Finance

Advances on revolving credit and term facilities

355

1.20

205

1.46

NMGC

Advances on revolving credit facilities

1.20

1.22

GBPC

Advances on revolving credit facilities

5.25

NSPI

Bank indebtedness

Short-term debt

1,742

1,625

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 Canadian dollars

Maturity

2021

2020

Tampa

Electric Company - revolving credit facility

2026

1,014

1,019

TECO Energy/TECO Finance - revolving credit facility

2026

507

509

Emera - non-revolving term facility

2022

400

TEC - term loan

2022

634

382

TEC - accounts receivable revolving credit facility

191

NMGC - revolving credit facility

2026

158

159

GBPC - revolving credit facility

on demand

Total

2,729

2,677

Less:

Advances under revolving credit and term facilities

1,735

1,624

Letters of credit issued within the credit facilities

Total

advances under available facilities

1,739

1,628

Available capacity under existing agreements

990

1,049

The weighted average interest rate on outstanding short-term

debt at December 31, 2021 was

0.83

per

cent (2020 –

1.01

per cent).

Recent Significant Financing Activity by Segment

Florida Electric Utility

On December 17, 2021, TEC entered into a $

500

million USD unsecured, non-revolving credit facility

with

a maturity date of

December 16, 2022

. The credit facility contains customary representations

and

warranties, events of default, financial and other covenants

and bears interest based on either the

London Inter-Bank Offered Rate (“LIBOR”), prime

rate, or the federal funds rate, plus a margin.

On December 17, 2021, TEC amended and restated its

800

million USD revolving credit facility.

The

amendment extended the maturity date from

March 22, 2023

December 17, 2026

. There were no other

significant changes in commercial terms from the prior

agreement.

On May 25, 2021, TEC established a commercial paper

program. Amounts available under the

commercial paper program may be borrowed, repaid and reborrowed

with the aggregate amount of the

notes outstanding at any time not to exceed $

800

million USD. The full amount of commercial

paper

issued is backed by TEC’s credit facility and results

in an equal amount of its credit facility being

considered drawn and unavailable.

As a result of the $

800

million USD senior notes issuance (refer to note 25),

on March 23, 2021, TEC

repaid its $

300

million USD non-revolving term loan. TEC also repaid its

150

million USD accounts

receivable collateralized borrowing facility and the agreement

subsequently matured and terminated on

March 22, 2021.

Gas Utilities and Infrastructure

On December 17, 2021, NMGC amended and restated

its $

125

million USD revolving credit facility.

The

amendment extended the maturity date from

March 22, 2023

December 17, 2026

. There were no other

significant changes in commercial terms from the prior

agreement.

Other

On December 17, 2021, TECO Finance amended and

restated its $

400

million USD revolving credit

facility. The amendment

extended the maturity date from

March 22, 2023

December 17, 2026

. There

were no other significant changes in commercial terms

from the prior agreement.

On December 3, 2021, Emera extended the maturity date

of its $

400

million non-revolving term loan from

December 16, 2021

December 16, 2022

. There were no other significant changes in commercial

terms

from the prior agreement.

24.

OTHER CURRENT LIABILITIES

As at

December 31

millions of Canadian dollars

2021

2020

Accrued charges

157

141

Accrued interest on long-term debt

Pension and post-retirement liabilities (note 21)

Sales and other taxes payable

Income tax payable

Other

366

340

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 Canadian dollars

2021

2020

Maturity

2021

2020

Emera

Bankers acceptances, LIBOR loans

Variable

2026

378

263

Unsecured fixed rate notes

2.90%

2023

500

Fixed to floating subordinated notes (USD)

(2)

6.75%

2076

1,521

1,528

2,399

2,291

Emera Finance

Unsecured senior notes (USD)

3.65%

3.86%

2024 - 2046

3,487

3,501

TECO Finance

Tampa Electric

(3)

Fixed rate notes and bonds (USD)

4.15%

4.53%

2022 - 2051

3,683

3,268

PGS

Fixed rate notes and bonds (USD)

3.78%

4.58%

2022 - 2051

660

429

NMGC

Fixed rate notes and bonds (USD)

3.11%

4.30%

2026 - 2051

488

465

Non-revolving term facility, floating rate

Variable

2022

101

589

465

NMGI

Fixed rate notes and bonds (USD)

3.64%

2024

190

191

NSPI

Discount notes

Variable

2026

376

291

Medium term fixed rate notes

5.14%

2025 - 2097

2,665

3,041

2,956

EBP

Senior secured credit facility

Variable

2025

249

ECI

Secured senior notes (USD)

Variable

2026

106

Amortizing fixed rate notes (USD)

3.97%

3.92%

2022 - 2026

104

100

Non-revolving term facility, floating rate

Variable

2025

Non-revolving term facility, fixed rate

2.36%

2.60%

2025 - 2026

101

Secured fixed rate senior notes

(4)

4.43%

4.39%

2022 - 2035

161

174

478

476

Adjustments

Fair market value adjustment - TECO Energy acquisition

(5)

Debt issuance costs

(121)

(110)

Amount due within one year

(462)

(1,382)

(580)

(1,487)

Long-Term Debt

14,196

12,339

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

(2) In 2021, the company recognized $

102

million in interest expense (2020 - $

109

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,

BBD or East Caribbean Dollar (XCD).

(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 Canadian dollars

Maturity

2021

2020

Emera – revolving credit facility

(1)

June 2026

900

NSPI - revolving credit facility

(1)

December 2026

600

ECI – revolving credit facilities

2022-2032

Total

1,527

1,528

Less:

Borrowings under credit facilities

770

569

Letters of credit issued inside credit facilities

124

Use of available facilities

894

600

Available capacity under existing agreements

633

928

(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, 2021

Emera

Syndicated credit facilities

Debt to capital ratio

Less than or equal to

0.70

to 1

0.57

: 1

Recent Significant Financing Activity by Segment

Florida Electric Utility

On May 15, 2021, TEC repaid its $

278

million USD,

5.4

per cent notes upon maturity.

The notes were

repaid using existing credit facilities.

On March 18, 2021, TEC completed an issuance of $

800

million USD senior notes. The issuance

included $

400

million USD senior notes that bear interest at a rate

2.40

per cent with a maturity date of

March 15, 2031

and $

400

million USD senior notes that bear interest at a rate of

3.45

per cent with a

maturity date of

March 15, 2051

Canadian Electric Utilities

On December 3, 2021, NSPI amended its operating credit

facility to extend the maturity from

October

2024

December 2026

. There were no other significant changes in commercial

terms from the prior

agreement.

Other Electric

On December 16, 2021, GBPC entered into a $

million USD

4.00

per cent term loan with a maturity

date of

December 31, 2026

. Proceeds from this loan were used to repay existing,

non-revolving term

loans totaling $

million USD and to fund operations.

Gas Utilities and Infrastructure

On July 16, 2021, Brunswick Pipeline extended the maturity date

of its $

250

million credit facility from

May 17, 2023

June 30, 2025

. There were no other significant changes in commercial

terms from the

prior agreement.

On March 25, 2021, NMGC entered into a $

100

million USD unsecured, non-revolving credit facility

with a

maturity date of

September 23, 2022

. The credit facility contains customary representations

and

warranties, events of default, financial and other covenants

and bears interest based on either the LIBOR,

prime rate, or the federal funds rate, plus a margin.

On February 5, 2021, NMGC completed an issuance of

220

million USD senior notes. The issuance

included $

million USD senior notes that bear interest at a rate

2.26

per cent with a maturity date of

February 5, 2031

, $

million USD senior notes that bear interest at a rate

2.51

per cent and with a

maturity date of

February 5, 2036

, and $

million USD senior notes that bear interest at a

rate of

3.34

per cent with a maturity date of

February 5, 2051

. Proceeds from this issuance were used to repay

200

million USD note due in 2021, which was classified as

long-term debt at December 31, 2020.

Other

On July 23, 2021, Emera extended the maturity date of

its $

900

million unsecured committed revolving

credit facility from

June 30, 2024

June 30, 2026

. There were no other significant changes in

commercial terms from the prior agreement.

On June 4, 2021 Emera US Finance LP completed an issuance

of $

750

million USD senior notes. The

issuance included $

450

million USD senior notes that bear interest at a rate of

2.64

per cent with a

maturity date of

June 15, 2031

and $

300

million USD senior notes that bear interest at a rate

0.83

per

cent with a maturity date of

June 15, 2024

. The USD senior notes are guaranteed by Emera

and Emera

US Holdings Inc., a wholly owned Emera subsidiary.

From the $

750

million USD senior notes issuance discussed above, on

June 15, 2021, Emera US

Finance LP repaid its previously outstanding $

750

million USD senior notes on maturity.

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 Canadian dollars

2022

2023

2024

2025

2026

Thereafter

Total

Emera

500

1,899

2,399

Emera US Finance LP

571

951

1,965

3,487

Tampa

Electric

285

3,398

3,683

PGS

628

660

NMGC

101

399

589

NMGI

190

NSPI

125

416

2,500

3,041

EBP

249

ECI

130

124

478

Total

462

590

827

504

3,479

8,914

14,776

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 Canadian dollars

2021

2020

Balance, January 1

178

185

Additions

Liabilities settled

(1)

(13)

(25)

Accretion included in depreciation expense

Accretion deferred to regulatory asset (included in property, plant and equipment)

(2)

(3)

Other

Change in foreign exchange rate

(1)

Balance, December 31

174

178

(1) Tampa Electric produces ash and other by-products, collectively known as CCR's, at

its Big Bend and Polk power stations. The

decreases in ARO in 2021 and 2020 are due

to the closure of CCR management facilities.

27.

COMMITMENTS AND CONTINGENCIES

Commitments

As at December 31, 2021, 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 Canadian dollars

2022

2023

2024

2025

2026

Thereafter

Total

Transportation

(1)

563

437

372

323

297

2,627

4,619

Purchased power

(2)

231

227

244

242

235

1,967

3,146

Fuel, gas supply and storage

694

104

908

Capital Projects

359

457

Long-term service agreements

(3)

303

Equity investment commitments

(4)

240

Leases and other

(5)

116

175

Demand side management

2,195

942

726

650

588

4,793

9,894

(1)

Purchasing commitments for transportation of

fuel and transportation capacity on various pipelines. Includes

a commitment of

142

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)

Maintenance of certain generating equipment,

services related to a generation facility and

wind operating agreements,

outsourced management of computer and communication

infrastructure and vegetation management.

(4)

Emera has a commitment to make equity

contributions to the LIL.

(5)

Includes operating lease agreements for buildings,

land, telecommunications services and rail cars, transmission

rights and

investment commitments.

NSPI has a contractual obligation to pay NSPML for the

use of the Maritime Link over approximately

years

from its January 15, 2018 in-service date. As part of NSPI’s

2020 through 2022 fuel stability plan,

rates have been set to include $

164

million and $

162

million for 2021 and 2022, respectively.

The timing

and amounts payable to NSPML for the remainder of

the

-year commitment period are subject to

UARB approval. Any difference between the amounts

included in the NSPI fuel stability plan and those

approved by the UARB through the NSPML interim assessment

application will be addressed through the

FAM. On August 9, 2021,

NSPML filed a final capital cost application with the UARB

seeking approval to

recover capital costs associated with the Maritime Link

and approval of NSPML’s

2022 assessment.

December 2021, NSPML obtained an interim decision

from the UARB approving interim rates beginning

January 1, 2022, until receipt of the UARB’s

decision on the application. On February 9, 2022, the UARB

issued its decision relating to the Maritime Link Project,

approving NSPML’s

requested rate base of

approximately $

1.8

billion less costs that would not otherwise have been recoverable

if incurred by NSPI.

For further information on the UARB decision, refer to

note

Once Muskrat Falls and LIL have achieved full power,

the commercial agreements between Emera and

Nalcor require true ups to finalize the respective investment

obligations of the parties relating to the

Maritime Link and LIL.

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 commenced, and continuing for

50 years

. As transmission rights are contracted, the

obligations are included within “Leases and 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 this Second Award. On October

16, 2020, the tribunal granted TGH’s request

for

additional interest. The additional amount is approximately $

million USD. On February 12, 2021,

Guatemala filed an application for annulment of the Second

Award with ICSID. On March 31, 2021, ICSID

constituted an ad hoc Committee to oversee the annulment proceeding.

On May 17, 2021, the ad hoc

Committee issued (i) a decision continuing the stay of

enforcement of the Second Award until the

committee renders its decision on Guatemala’s

application for annulment and (ii) an order with dates for

briefings on the annulment and a hearing commencing July 27,

2022.

Guatemala filed its Memorial on

Annulment on August 25, 2021.

TGH’s Counter-Memorial on Annulment was filed

on December 8, 2021.

date, the total of the Second Award, with interest,

is approximately $

million USD. Results to date

do not reflect any benefit of the Second Award.

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, 2021, TEC has 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,

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 a business-wide risk management process, monitored

the Board of Directors, to ensure a consistent and coherent

approach to risk management. The Board of

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

in September 2021. The mandate of

the RSC is to assist the Board in carrying out its risk and

sustainability oversight responsibilities and

includes oversight of the Company’s Enterprise Risk

Management framework, including the identification,

assessment, monitoring and management

of enterprise risks.

Public Health Risk

An outbreak of infectious disease, a pandemic or a similar

public health threat, such as the COVID-19

pandemic, or a fear of any of the foregoing, could adversely

impact the Company,

including causing

operating, supply chain and project development delays

and disruptions, labour shortages and shutdowns

(including as a result of government regulation and

prevention measures), which could have a negative

impact on the Company’s operations.

Any adverse changes in general economic and market conditions

arising as a result of a public health

threat could negatively impact demand for electricity and natural

gas, revenue, operating costs, timing

and extent of capital investments, results of financing

efforts, or credit risk and counterparty risk;

which

could result in a material adverse

effect on the Company’s business. The

Company maintains pandemic

and business contingency plans in each of its operations

to manage and help mitigate the impact of any

such public health threat.

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

Canadian dollar and, particularly,

the US dollar,

which could positively or adversely affect results.

Consistent with the Company’s risk management

policies, Emera manages currency risks through

matching US denominated debt to finance its US operations

and may use foreign currency derivative

instruments to hedge specific transactions and earnings

exposure. The Company may enter foreign

exchange forward and swap contracts to limit exposure on certain

foreign currency transactions such as

fuel purchases, revenue streams and capital investment

s, 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 foreign exchange.

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. The Company reasonably expects liquidity sources

to exceed capital needs.

Emera’s access to capital and cost of borrowing

is subject to several risk factors, including financial

market conditions, market disruptions, and ratings assigned

by 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 property,

plant and equipment 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

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

and

regulatory framework, 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.

Interest Rate Risk

Emera utilizes a combination of fixed and floating rate debt financing

for operations and capital

investments, 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.

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. The Company’s commercial

arrangements, including the combination of supply

and purchase agreements, asset management agreements,

pipeline transportation agreements and

financial hedging instruments are all used to manage and

mitigate this risk. 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

A large portion of the Company’s utility fuel supply comes

from international suppliers and therefore may

be exposed to broader global conditions, which may include

impacts on delivery reliability and price,

despite contracted terms. The Company seeks to manage this

risk using financial hedging instruments

and physical contracts and through contractual protectio

with counterparties, where applicable.

The majority of Emera’s regulated electric and gas

utilities have adopted and implemented fuel

adjustment mechanisms and purchased gas adjusted

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.

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.

measure commodity price risk exposure, Emera Energy employs

a number of controls and processes,

including an estimated value-at-risk (“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

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

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, 2021:

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 or S&P,

TECO Energy would be required to provide its counterparty

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

In 2021, NSPI issued guarantees in the amount of $

million USD on behalf of its subsidiary,

NS Power

Energy Marketing Incorporate (“NSPEMI”), to secure

obligations under purchase agreements with third-

party suppliers and $

million USD related to a

-year natural gas transportation commitment. NSPI

has $

118

million USD (2020 - $

million USD) of guarantees outstanding with terms

of varying lengths

and will be renewed as required.

The Company has standby letters of credit and surety

bonds in the amount of $

148

million USD

(December 31, 2020 - $

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 2022. The amount committed

as at December 31, 2021 was $

million (December 31, 2020 - $

million).

Collaborative Arrangements

For the years ended December 31, 2021 and 2020, 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

expenses. In 2021, NSPI recognized $

million net expense (2020 - $

million) in “Regulated fuel for

generation and purchased power” and $

million (2020 - $

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, 2021

December 31, 2020

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

25.25

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

Series L

1.1500

25.00

9,000,000

222

Total

58,000,000

1,422

41,000,000

1,004

First Preferred Shares, Series J

On April 6, 2021, Emera issued

million,

4.25

per cent Cumulative Minimum Rate Reset First Preferred

Shares, Series J

(“First Preferred Shares, Series J”) at $

25.00

per share for gross proceeds of $

200

million ($

196

million, net of after-tax issuance costs).

First Preferred Shares, Series L

On September 24, 2021, Emera issued

million,

4.60

per cent Cumulative Redeemable First Preferred

Shares, Series L

(“First Preferred Shares, Series L”) at $

25.00

per share for gross proceeds of $

225

million ($

222

million, net of after-tax issuance costs).

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

25.25

Series L

(6)

4.600

1.1500

November 15, 2026

25.00

(1) Holders are entitled to receive fixed or floating

cumulative cash dividends when declared by the

Board of Directors of the

Corporation.

(2) On or after the specified redemption dates,

the Corporation has the option to redeem

for cash the outstanding First Preferred

Shares, in whole or in part, at the specified per

share redemption value plus all accrued and

unpaid dividends up to but excluding the

dates fixed for redemption.

(3) On the redemption and/or conversion option

date the reset annual dividend per share will be

determined by multiplying $

25.00

per

share by the annual fixed or floating dividend

rate, which for Series A, C, F and H is

the sum of the five-year Government of Canada

Bond Yield on the applicable reset date, plus the applicable

reset dividend yield (Series H annual reset

rate must be a minimum of

4.90

per cent) and for Series B equals the Government

of Treasury Bill Rate on the applicable reset date, plus

1.84

per cent.

(4) On each conversion option date, the holders

have the option, subject to certain conditions,

to convert any or all of their Shares

into an equal number of Cumulative Redeemable

First Preferred Shares of a specified series.

The Company has the right to redeem

the outstanding Preferred Shares, Series D, Series

G and Series I shares without the consent

of the holder every five years thereafter

for cash, in whole or in part at a price of

25.00

per share plus all accrued and unpaid

dividends up to but excluding the date fixed for

redemption and $

25.50

per share plus all accrued and unpaid

dividends up to but excluding the date

fixed for redemption in the case

of redemptions on any other date after August 15,

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 $

25.25

to August 15, 2022 and $

25.00

per share thereafter.

(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 is deducted on the

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

and is 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 Canadian dollars

2021

2020

Preferred shares of GBPC

Domlec

Preferred shares of GBPC:

Authorized:

10,000 non-voting cumulative redeemable variable perpetual

preferred shares.

2021

2020

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 Canadian dollars

2021

2020

Changes in non-cash working capital:

Inventory

(84)

Receivables and other current assets

(364)

187

Accounts payable

289

Other current liabilities

(31)

Total

non-cash working capital

(152)

217

Supplemental disclosure of cash paid (received):

Interest

603

679

Income taxes

(148)

Supplemental disclosure of non-cash activities:

Common share dividends reinvested

214

199

Reclassification of long-term debt from current to non-current

256

(Decrease) Increase in accrued capital expenditures

(45)

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, 2021, 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 (2020 –

million common shares). As at December 31, 2021,

Emera is in

compliance with this requirement.

Compensation cost for shares issued by Emera for the year

ended December 31, 2021 under the

Employee Common Share Purchase Plan was $

million (2020 – $

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”) or (“DRIP”), 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 2021.

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 market price of the stocks

on the day before the option is granted. The maximum aggregate number of shares issuable under this

plan is 14.7 million shares. As at December 31, 2021, Emera is in compliance with this requirement.

Stock options vest in 25 per cent increments on the first, second, third and fourth 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.

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. 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:

2021

2020

Weighted average fair value per option

3.63

3.58

Expected term

(1)

years

Risk-free interest rate

(2)

0.60

1.33

Expected dividend yield

(3)

5.00

4.09

Expected volatility

(4)

19.14

14.10

(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 2021:

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, 2020

2,267,782

46.62

1,293,850

2.69

Granted

653,600

51.12

653,600

3.63

Exercised

(331,078)

40.97

N/A

Vested

N/A

(494,975)

2.49

Options outstanding December 31, 2021

2,590,304

48.48

1,452,475

3.18

Options exercisable December 31, 2021

(2)(3)

1,137,829

44.86

(1) As at December 31, 2021, 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 (2020 - $

million,

years).

(2) As at December 31, 2021, the weighted

average remaining term of vested options was

years with an aggregate intrinsic value of

million (2020 - $

million,

years).

(3) As at December 31, 2021, the fair value of

options that vested in the year was $

million (2020 - $

million).

Compensation cost recognized for stock options for the year

ended December 31, 2021 was $

million

(2020 – $

million), which is included in OM&G on the Consolidated

Statements of Income.

As at December 31, 2021, cash received from option exercises

was $

million (2020 – $

million). The

total intrinsic value of options exercised for the year ended

December 31, 2021 was $

million (2020 – $

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

as at December 31, 2021 was $

32.35

60.03

(2020 – $

32.06

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 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 usually made in cash. At the sole discretion of the Management Resources and

Compensation Committee (“MRCC”), payments may be made in the form of actual shares.

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

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

A summary of the activity related to employee and director

DSUs for the year ended December 31, 2021

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, 2020

661,998

37.17

591,124

41.69

Granted including DRIP

93,710

49.64

101,403

51.25

Exercised

(145,107)

36.61

(78,162)

37.57

Outstanding and exercisable as at December 31, 2021

610,601

39.22

614,365

43.80

Compensation cost recognized for employee and director

DSU’s for the year ended December 31, 2021

was $

million (2020 – $

million). Tax

benefits related to this compensation cost for share

units realized

for the year ended December 31, 2021 were $

million (2020 – $

million). The aggregate intrinsic value

of the outstanding shares for the year ended December

31, 2021 for employees was $

million (2020 -

million). The aggregate intrinsic value of the outstanding

shares for the year ended December 31,

2021 for directors was $

million (2020 - $

million). Cash payments made during the year ended

December 31, 2021 associated with the DSU plan was

million (2020 - $

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, 2021 is presented

in the following table:

Employee PSU

Weighted Average

Grant Date Fair Value

Aggregate intrinsic value

Outstanding as at December 31, 2020

1,126,529

47.16

Granted including DRIP

323,610

52.83

Exercised

(464,290)

48.13

Forfeited

(33,914)

47.78

Outstanding as at December 31, 2021

951,935

48.60

Compensation cost recognized for the PSU plan for the

year ended December 31, 2021 was $

million

(2020 – $

million). Tax

benefits related to this compensation cost for share

units realized for the year

ended December 31, 2021 were $

million (2020 – $

million). Cash payments made during the year

ended December 31, 2021 associated with the PSU plan was

million (2020 – $

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, 2021 is presented

in the following table:

Employee RSU

Weighted Average

Grant Date Fair Value

Aggregate intrinsic value

Outstanding as at December 31, 2020

166,275

54.62

Granted including DRIP

184,498

54.66

Exercised

(232)

54.62

Forfeited

(6,589)

54.63

Outstanding as at December 31, 2021

343,952

54.64

Compensation cost recognized for the RSU plan for the

year ended December 31, 2021 was $

million

(2020 – $

million). Tax

benefits related to this compensation cost for share

units realized for the year

ended December 31, 2021 were $2 million (2020 – $

million). Cash payments made during the year

ended December 31, 2021 associated with the RSU plan was

nil (2020–

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, 2021

December 31, 2020

Maximum

millions of Canadian dollars

Total

assets

exposure to

loss

Total

assets

exposure to

loss

Unconsolidated VIEs in which Emera has variable interests

NSPML (equity accounted)

533

547

33.

SUBSEQUENT EVENTS

These financial statements and notes reflect the Company’s

evaluation of events occurring subsequent to

the balance sheet date through February 14, 2022, the date

the financial statements were issued.