EX-99.2

Management’s Discussion & Analysis

As at February 23, 2023

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

Incorporated and its subsidiaries and investments during the fourth quarter of 2022 relative to the same

quarter in 2021; for the full year of 2022 relative to 2021 and selected financial information for 2020; and

its financial position as at December 31, 2022 relative to December 31, 2021. Throughout this discussion,

“Emera” and “Company” refer to Emera Incorporated and all of its consolidated subsidiaries and

investments. The Company’s activities are carried out through five reportable segments: Florida Electric

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

This discussion and analysis should be read in conjunction with the Emera annual audited consolidated

financial statements and supporting notes as at and for the year ended December 31, 2022.

Emera

follows United States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”).

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

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

revenues and expenses. At December 31, 2022, Emera’s rate-regulated subsidiaries and investments

include:

Emera Rate-Regulated Subsidiary or Equity

Investment

Accounting Policies Approved/Examined By

Subsidiary

Tampa Electric – Electric Division of Tampa

Electric

Company (“TEC”)

(1)

Florida Public Service Commission (“FPSC”) and the

Federal Energy Regulatory Commission (“FERC”)

Nova Scotia Power Inc. ("NSPI")

Nova Scotia Utility and Review Board (“UARB”)

Peoples Gas System (“PGS”) – Gas Division of TEC

(1)

FPSC

New Mexico Gas Company, Inc. (“NMGC”)

New Mexico Public Regulation Commission (“NMPRC”)

SeaCoast Gas Transmission, LLC ("SeaCoast")

FPSC

Emera Brunswick Pipeline Company Limited (“Brunswick

Pipeline”)

Canadian Energy Regulator ("CER")

Barbados Light & Power Company Limited (“BLPC”)

Fair Trading Commission, Barbados ("FTC")

Grand Bahama Power Company Limited (“GBPC”)

The Grand Bahama Port Authority (“GBPA”)

Equity Investments

NSP Maritime Link Inc. (“NSPML”)

UARB

Labrador Island Link Limited Partnership (“LIL”)

Newfoundland and Labrador Board of Commissioners of

Public Utilities ("NLPUB")

Maritimes & Northeast Pipeline Limited Partnership and

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

CER and FERC

St. Lucia Electricity Services Limited (“Lucelec”)

National Utility Regulatory Commission (“NURC”)

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

reorganized, resulting in a

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

Inc.

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

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

(“USD”) unless otherwise stated.

Additional information related to Emera, including the Company’s Annual Information Form, can be found

on SEDAR at www.sedar.com.

TABLE

OF CONTENTS

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

Introduction and Strategic Overview………….…

Non-GAAP Financial Measures and Ratios….…

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

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

Consolidated Financial Highlights……………

Consolidated Income Statement Highlights…

Business Overview and

Outlook…………….……

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

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

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

Other Electric Utilities …………………………

Other……………………………………………

Consolidated Balance Sheet Highlights………

Other Developments……………….....................

Financial Highlights……………………………..

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

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

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

Other Electric Utilities ………………………….

Other…………………………………………….

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

Consolidated Cash Flow Highlights…..……

Working Capital

Contractual Obligations….……………………

Forecasted Gross Consolidated Capital

Expenditures………………………………

Debt Management……..…………………….

Credit Ratings…………………………………

Guaranteed Debt……………………………

Outstanding Stock Data……………………

Pension Funding………………………………

Off-Balance Sheet Arrangements…….………

Dividend Payout Ratio…………………………

Transactions with Related Parties….………….

Enterprise Risk and Risk Management…………

Risk Management including Financial

Instruments……………………………………

Disclosure and Internal Controls……….…….

Critical Accounting Estimates….………………

Changes in Accounting Policies and

Practices…

Future Accounting Pronouncements…………

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

FORWARD-LOOKING INFORMATION

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

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

carbon dioxide emissions reduction goals, business prospects and opportunities,

and may not be

appropriate for other purposes within the meaning of applicable Canadian securities laws. All such

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

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

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

similar expressions are often intended to identify forward-looking information, although not all forward-

looking information contains these identifying words. The forward-looking information reflects

management’s current beliefs and is based on information currently available to Emera’s management

and should not be read as guarantees of future events, performance or results, and will not necessarily

be accurate indications of whether, or the time at which, such events, performance or results will be

achieved.

The forward-looking information is based on reasonable assumptions and is subject to risks, uncertainties

and other factors that could cause actual results to differ materially from historical results or results

anticipated by the forward-looking information. Factors that could cause results or events to differ from

current expectations include, without limitation: regulatory and political risk; operating and maintenance

risks; changes in economic conditions; commodity price and availability risk; liquidity and capital market

risk; future dividend growth; timing and costs associated with certain capital investments; expected

impacts on Emera of challenges in the global economy; estimated energy consumption rates;

maintenance of adequate insurance coverage; changes in customer energy usage patterns;

developments in technology that could reduce demand for electricity; global climate change; weather;

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

financial instruments and hedging; interest rate risk; inflation risk; counterparty risk; disruption of fuel

supply; country risks; environmental risks; foreign exchange (“FX”); regulatory and government decisions,

including changes to environmental, financial reporting and tax legislation; risks associated with pension

plan performance and funding requirements; loss of service area; risk of failure of information technology

(“IT”) infrastructure and cybersecurity risks; uncertainties associated with infectious diseases, pandemics

and similar public health threats, such as the COVID-19 novel coronavirus (“COVID-19”) pandemic;

market energy sales prices; labour relations; and availability of labour and management resources.

Readers are cautioned not to place undue reliance on forward-looking information,

as actual results could

differ materially from the plans, expectations, estimates or intentions and statements expressed in the

forward-looking information. All forward-looking information in this MD&A is qualified in its entirety by the

above cautionary statements and, except as required by law, Emera undertakes no obligation to revise or

update any forward-looking information as a result of new information, future events or otherwise.

INTRODUCTION AND STRATEGIC

OVERVIEW

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

utilities in Canada, the United States and the Caribbean. Cost-of-service utilities provide essential electric

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

Emera’s strategic focus continues to be safely delivering cleaner, affordable and reliable energy to its

customers.

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

investments in Nova Scotia, New Mexico and the Caribbean.

Emera’s portfolio of regulated utilities

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

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

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

Earnings are also affected by sales volumes and operating expenses.

Emera’s capital investment plan is $8 – 9 billion over the 2023-to-2025 period (including a $240 million

equity investment in the LIL in 2023), mainly focused in Florida. This results in a forecasted rate base

growth of approximately 7 per cent to 8 per cent through 2025. The capital investment plan continues to

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

integrity investments, infrastructure modernization, and customer-focused technologies. Emera’s capital

investment plan is being funded primarily through internally generated cash flows and debt raised at the

operating company level. Equity requirements in support of the Company’s capital investment plan are

expected to be funded through the issuance of preferred equity and the issuance of common equity

through Emera’s dividend reinvestment plan (“DRIP”) and at-the-market program (“ATM program”).

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

Emera has provided annual dividend growth guidance of four to five per cent through 2025. The

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

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

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

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

section.

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

market adjustments and foreign currency exchange can have a material impact on financial results for a

specific period. Emera’s consolidated net income and cash flows are impacted by movements in the USD

relative to the Canadian dollar. Emera may hedge both transactional and translational exposure. These

impacts, as well as the timing of capital investments and other factors, mean results in any one quarter

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

Energy markets worldwide are facing significant change and Emera is well positioned to respond to

shifting customer demands, digitization, decarbonization, complex regulatory environments, and

decentralized generation.

Customers are looking for more choice, better control, and enhanced reliability in a time where costs of

decentralized generation and storage have become more competitive in some regions. Advancing

technologies are transforming the way utilities interact with their customers and generate and transmit

energy. In addition, climate change and extreme weather are shaping how utilities operate and how they

invest in infrastructure. There is also an overall need to replace aging infrastructure and further enhance

reliability. Emera will play a role in all of these trends. Emera’s strategy is to fund investments in

renewable energy and technology assets which protect the environment and benefit customers through

fuel or operating cost savings.

For example, significant investments to facilitate the use of renewable and low-carbon energy include the

Maritime Link in Atlantic Canada, and the ongoing construction of solar generation and modernization of

the Big Bend Power Station at Tampa

Electric. Emera’s utilities are also investing in reliability projects

and replacing aging infrastructure. All of these projects demonstrate Emera’s strategy of safely delivering

cleaner, reliable, and affordable energy for its customers.

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

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

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

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

and subject to supportive

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

corresponding 2005 levels:

•

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

•

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

•

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

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

and other external factors beyond Emera's control.

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

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

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

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

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

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

NON-GAAP FINANCIAL MEASURES AND RATIOS

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

may not be comparable to similar measures presented by other entities. Emera calculates the non-GAAP

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

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

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

below.

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

Common Share (“EPS”) – Basic and Dividend Payout Ratio of Adjusted Net Income

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

measure by excluding the effect of mark-to-market (“MTM”) adjustments,

impairment charges, the impact

of the NSPML unrecoverable costs, and the 2020 gain on sale of Emera Maine.

Management believes excluding from net income the effect of these MTM valuations and changes

thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying

cash flows, and therefore excludes these MTM adjustments for evaluation of performance and incentive

compensation. The MTM adjustments are related to the following:

●

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

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

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

marketing and trading transactions;

●

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

equity income;

●

equity securities held in BLPC and a captive reinsurance company in the Other segment; and

●

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

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

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

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

GBPC due to a decline in the fair value of the reporting unit. The fair value decline was driven by the

effects of macro-economic factors on the discount rate calculation, including the risk-free rate

assumption. Management believes excluding from net income the effect of this charge better

distinguishes ongoing operations of the business and allows investors to better understand and evaluate

the Company. For further details on this GBPC impairment charge, refer to “Significant Items Impacting

Earnings”, and “Financial Highlights – Other” sections.

In February 2022, the UARB issued a decision to disallow the recovery of $9 million in costs ($7 million

after-tax) included in NSPML’s final capital cost application. The after-tax unrecoverable costs were

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

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

better reflects the underlying operations in the period. For further details on the NSPML unrecoverable

costs, refer to the “Business Overview and Outlook – Canadian Electric Utilities” and “Financial Highlights

– Canadian Electric Utilities” sections.

In 2020, the Company recognized a gain on the sale of Emera Maine and certain non-cash impairment

charges. Management believes excluding these from net income better distinguishes ongoing operations

of the business and allows investors to better understand and evaluate the business.

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

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

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

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

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

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

Highlights – Other” sections.

The following reconciles net income attributable to common shareholders to adjusted net income:

Three months ended

Year ended

For the

December 31

millions of dollars (except per share amounts)

2022

2021

2022

2021

2020

Net income attributable to common shareholders

483

324

945

510

938

MTM gain (loss), after-tax

(1)

307

156

175

(213)

(10)

Impairment charges, after-tax

(2)

(73)

(26)

NSPML unrecoverable costs

(3)

(7)

Gain on sale, after tax and transaction costs

(4)

309

Adjusted net income attributable to common shareholders

249

168

850

723

665

EPS – basic

1.80

1.24

3.56

1.98

3.78

Adjusted EPS – basic

0.93

0.64

3.20

2.81

2.68

(1) Net of income tax expense of $124 million for the three months ended December 31, 2022 (2021 – $63 million expense)

and $73

million expense for the year ended December 31, 2022 (2021 – $86 million recovery) (2020 - $8 million recovery).

(2) Net of income tax expense of nil for the three months and year ended December 31, 2022 (2021 – nil) (2020 – $1 million

expense).

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

in “Income

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

(4) Net of income tax expense of $276 million for the year ended December 31, 2020.

EBITDA and Adjusted EBITDA

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

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

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

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

capital, and finance working capital requirements.

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

absent the income effect of MTM adjustments, impairment charges, the NSPML unrecoverable costs, and

the 2020 gain on sale of Emera Maine.

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

Three months ended

Year ended

For the

December 31

millions of dollars

2022

2021

2022

2021

2020

Net income

(1)

499

338

1,009

561

984

Interest expense, net

206

151

709

611

679

Income tax expense (recovery)

154

185

(6)

341

Depreciation and amortization

254

227

952

902

881

EBITDA

1,113

801

2,855

2,068

2,885

MTM gain (loss), excluding income tax

431

219

248

(299)

(18)

Impairment charges, excluding income tax

(73)

(25)

NSPML unrecoverable costs

(2)

(7)

Gain on sale, net of transaction costs (excluding income tax)

585

Adjusted EBITDA

755

582

2,687

2,367

2,343

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

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

in “Income

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

CONSOLIDATED

FINANCIAL REVIEW

Significant Items Affecting Earnings

GBPC Impairment Charge

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

GBPC due to a decline in the fair value of the reporting unit. Although the cash flows of GBPC have not

changed significantly compared to previous periods, the decline in the fair value was driven by the effects

of macro-economic factors on discount rate calculations, including the risk-free rate assumption. This

non-cash charge was recorded in “Impairment charge” on the Consolidated Statements of Income and

reduced the GBPC goodwill balance to nil. For further details, refer to note 22 in the consolidated financial

statements.

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

On December 15, 2022, a payment of $63 million ($45 million after tax and legal costs, or $0.17 per

common share), was made by the Republic of Guatemala to TECO Energy in satisfaction of the second

and final award issued by the International Centre of the Settlement of Investment Disputes tribunal

regarding a dispute over an investment of TGH, a wholly owned subsidiary of TECO Energy. The dispute

related to the 2007 intervention by the government of Guatemala in an ongoing independent rate-setting

process to unilaterally set a new and lower tariff. The payment was recognized in ‘Other income, net” on

the Consolidated Statements of Income. For further details, refer to note 27 in the consolidated financial

statements.

Earnings Impact of MTM Gain (Loss), After-Tax

MTM gain, after-tax increased $151 million to $307 million in Q4 2022, compared to $156 million in Q4

2021, and for the year ended December 31, increased $388 million to $175 million compared to a MTM

loss, after-tax of $213 million for the same period in 2021. These increases were due to changes in

existing positions and reversal of losses in 2022, partially offset by higher amortization in 2022 of gas

transportation assets at Emera Energy.

Consolidated Financial Highlights

For the

Three months ended

Year ended

millions of dollars

December 31

Adjusted net income

2022

2021

2022

2021

2020

Florida Electric Utility

124

596

462

501

Canadian Electric Utilities

222

241

221

Gas Utilities and Infrastructure

221

198

162

Other Electric Utilities

Other

(1)

(44)

(218)

(198)

(252)

Adjusted net income

249

168

850

723

665

MTM gain (loss), after-tax

307

156

175

(213)

(10)

Impairment charges, after-tax

(73)

(26)

NSPML unrecoverable costs

(7)

Gain on sale, after tax and transaction costs

309

Net income attributable to common shareholders

483

324

945

510

938

The following table highlights the significant changes in adjusted net income from 2021 to 2022:

For the

Three months ended

Year ended

millions of dollars

December 31

Adjusted net income – 2021

168

723

Operating Unit Performance

Increased earnings at Tampa Electric due to higher revenues as a result

of rate increases effective January 2022, customer growth, and the

impact of a weakening CAD. These were partially offset by higher

operating, maintenance and general expenses (OM&G"), increased

interest expense, and higher depreciation. Year-over-year also

increased due to favourable weather

134

Increased earnings at Emera Energy Services ("EES") due to favourable

market conditions

Increased earnings at PGS due to higher off-system sales and customer

growth, partially offset by higher OM&G. Year-over-year also increased

due to reversal of accumulated depreciation as a result of the rate case

settlement

Increased earnings at Seacoast due to commencement of a 34-year

pipeline lateral lease in 2022

Increased earnings at NMGC were primarily due to higher asset

optimization revenues. Year-over-year increased earnings were partially

offset by higher OM&G and increased depreciation

Decreased earnings at NSPI due to higher OM&G primarily due to

increased costs for storm restoration, IT, power generation, regulatory

affairs, and higher depreciation. This was partially offset by higher sales

volumes. Quarter-over-quarter also decreased due to unfavourable

weather

(20)

(10)

Corporate

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

"Significant Items Affecting Earnings" section

Increased income tax recovery primarily due to increased losses before

provision for income taxes

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

and related hedges

(19)

(55)

Increased FX loss, pre-tax, primarily due to realized gains in 2021 on FX

hedges entered into to hedge USD denominated operating unit earnings

exposure

(9)

(28)

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

increased total debt

(17)

(27)

Increased preferred stock dividends due to issuance of preferred shares

in 2021

(2)

(13)

Other Variances

Adjusted net income – 2022

249

850

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

For the

Year ended December 31

millions of dollars

2022

2021

2020

Operating cash flow before changes in working capital

1,147

1,337

1,420

Change in working capital

(234)

(152)

217

Operating cash flow

913

1,185

1,637

Investing cash flow

(2,569)

(2,332)

(1,224)

Financing cash flow

1,555

1,311

(372)

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

As at

December 31

millions of dollars

2022

2021

2020

Total assets

39,742

34,244

31,234

Total long-term

debt (including current portion)

16,318

14,658

13,721

Consolidated Income Statement Highlights

For the

Three months ended

Year ended

millions of dollars

December 31

(except per share amounts)

2022

2021

Variance

2022

2021

Variance

2020

Operating revenues

2,358

1,868

490

7,588

5,765

1,823

5,506

Operating expenses

1,638

1,352

(286)

5,959

4,835

(1,124)

4,359

Income from operations

720

516

204

1,629

930

699

1,147

Net income attributable to

common shareholders

483

324

159

945

510

435

938

Adjusted net income

249

168

850

723

127

665

Weighted average shares of

common stock outstanding (in

millions)

(1)

269.0

260.8

8.2

265.5

257.2

8.3

247.8

EPS – basic

1.80

1.24

0.56

3.56

1.98

1.58

3.78

EPS – diluted

1.80

1.20

0.60

3.55

1.98

1.57

3.78

Adjusted EPS – basic

0.93

0.64

0.29

3.20

2.81

0.39

2.68

Adjusted EBITDA

755

582

173

2,687

2,367

320

2,343

Dividends per common share

declared

0.6900

0.6625

0.0275

2.6775

2.5750

0.1025

2.4750

Dividends per first preferred shares declared:

Series A

0.5456

0.6155

Series B

0.6869

0.4873

0.1996

0.6965

Series C

1.1802

Series E

1.1250

Series F

1.0505

1.0535

Series H

1.2250

Series J

1.0625

0.6470

0.4155

Series L

1.1500

0.1638

0.9862

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

therefore excluded from

weighted average shares of common stock outstanding.

Operating Revenues

For Q4 2022, operating revenues increased $490 million compared to Q4 2021 and, absent increased

MTM gains of $195 million, increased $295 million. For the year ended December 31, 2022, operating

revenues increased $1,823 million compared to 2021 and, absent increased MTM gains of $555 million,

increased by $1,268 million. The increases in both periods were due to: higher fuel revenues at NMGC,

Tampa

Electric PGS and BLPC; new rates effective January 2022 and customer growth at Tampa

Electric; the impact of a weaker CAD; higher off-system sales and customer growth at PGS; and

increased marketing and trading margin due to favourable market conditions at EES. Year-over-year also

increased due to increased sales volumes at NSPI and favourable weather at Tampa Electric.

Operating Expenses

For Q4 2022, operating expenses increased $286 million compared to Q4 2021 and, absent the GBPC

impairment charge of $73 million, increased by $213 million. For the year ended December 31, 2022,

operating expenses increased $1,124 million compared to 2021 and, absent the GBPC impairment

charge of $73 million, increased by $1,051 million. The increases in both periods were due to: higher

natural gas prices at NMGC and PGS; the impact of a weaker CAD; and increased OM&G at Tampa

Electric, Corporate, NSPI, NMGC and PGS. Year-over-year also increased due to higher natural gas and

fuel prices at Tampa

Electric and BLPC.

Other Income, Net

Other income, net increased for Q4 2022 and the year ended December 31, 2022, compared to the same

periods in 2021, primarily due to the TGH award in Q4 2022.

Net Income and Adjusted Net Income

Net income attributable to common shareholders for Q4 2022, as compared to Q4 2021, was favourably

impacted by the $151 million increase in MTM gains, after-tax and unfavourably impacted by the $73

million GBPC impairment charge. Absent these changes, adjusted net income increased $81 million. The

increase was primarily due to: the TGH award in Q4 2022; higher earnings contribution from Tampa

Electric, Emera Energy and NMGC; and the impact of a weaker CAD. These were partially offset by lower

earnings contribution from NSPI and increased corporate OM&G due to the timing of long-term

compensation and related hedges, and higher corporate interest expense.

Net income attributable to common shareholders for the year ended 2022, as compared to the same

period in 2021, was favourably impacted by the $388 million increase in MTM gains, after-tax and

unfavourably impacted by the $73 million GBPC impairment charge as well as the $7 million in NSPML

unrecoverable costs. Absent these changes, adjusted net income increased $127 million. The increase

was primarily due to: higher earnings contributions from Tampa Electric, Emera Energy,

PGS and

Seacoast; the TGH award in Q4 2022; and the impact of a weaker CAD. These were partially offset by

increased corporate OM&G due to the timing of long-term compensation and related hedges, higher

corporate interest expense, realized gains on corporate FX hedges in 2021, increased preferred stock

dividends and lower earnings contribution from NSPI.

EPS and Adjusted EPS – Basic

EPS and Adjusted EPS – basic were higher for Q4

2022, and for the year ended December 31, 2022,

due to the impact of higher earnings as discussed above, partially offset by the impact of the increase in

weighted average shares of common stock outstanding.

Effect of Foreign Currency Translation

Emera operates in Canada, the United States and various Caribbean countries and, as such, generates

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

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

positively or adversely affect results.

In general, Emera’s earnings benefit from a weakening CAD and are adversely impacted by a

strengthening CAD. The impact in any period is driven by rate changes, the timing and percentage of

earnings from foreign operations, and the impact of FX hedges entered into to hedge USD denominated

operating unit earnings exposure.

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

liabilities of foreign operations are translated at period end rates. The relevant CAD/USD exchange rates

for 2022 and 2021 are as follows:

Three months ended

Year ended

December 31

2022

2021

2022

2021

Weighted average CAD/USD

1.37

1.26

1.34

1.26

Period end CAD/USD exchange rate

1.35

1.27

1.35

1.27

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

recorded in USD currency.

Three months ended

Year ended

For the

December 31

millions of USD

2022

2021

2022

2021

Florida Electric Utility

458

369

Other Electric Utilities

Gas Utilities and Infrastructure

(1)

143

130

Other segment

(2)

(20)

(50)

(98)

Total

(3)

173

574

417

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

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

denominated debt.

(3) Excludes $222 million USD in MTM gain, after-tax, for the three months ended December 31, 2022 (2021 – $122 million

USD

MTM gain, after-tax) and MTM gain, after-tax of $130 million USD for the year ended December 31, 2022 (2021 – $164

million USD

MTM loss, after-tax) and the GBPC impairment charge of $54 million USD for the three months and year ended December

31, 2022

(2021 - nil).

The impact of the weakening CAD, partially offset by

the unrealized losses on FX hedges increased net

income by $42 million in Q4 2022 and $30 million for the year ended December 31, 2022, compared to

the same periods in 2021. Weakening of the CAD increased adjusted net income by $14 million in Q4

2022 and $28 million for the year ended December 31, 2022, compared to the same periods in 2021.

Impacts of the weakening CAD include the impacts of corporate FX hedges in the Other segment.

BUSINESS OVERVIEW AND OUTLOOK

Florida Electric Utility

Florida Electric Utility consists of Tampa Electric, a vertically integrated regulated electric utility engaged

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

Tampa

Electric has $12.1 billion USD of assets and approximately 827,000 customers at December 31,

2022. Tampa

Electric owns 6,549 megawatts (“MW”) of generating capacity, of which 78 per cent is

natural gas-fired, 15 per cent is solar and 7 per cent is coal. Tampa Electric owns 2,171 kilometres of

transmission facilities and 19,916 kilometres of distribution facilities. Tampa Electric meets the planning

criteria for reserve capacity established by the FPSC, which is a 20 per cent reserve margin over firm

peak demand.

Tampa

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

equity capital structure of 54 per cent. An ROE of 10.20 per cent will be used for the calculation of the

return on investments for clauses.

Tampa

Electric anticipates earning within its ROE range in 2023. New base rates effective January 1,

2023, as a result of the 2021 settlement agreement, will result in higher 2023 USD earnings than in 2022.

Normalizing 2022 for weather, Tampa

Electric sales volumes in 2023 are projected to be higher than in

2022 due to customer growth. Tampa Electric expects customer growth rates in 2023 to be comparable to

2022, reflective of the current expected economic growth in Florida.

On January 23, 2023, Tampa

Electric requested an adjustment to its fuel charges to recover the 2022 fuel

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

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

projected reduction of $170 million USD for the balance of 2023. The proposed changes will be decided

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

On September 28, 2022, Hurricane Ian made landfall in Southwest Florida as a Category 4 hurricane

and, as a result, approximately 291,000 customers lost power. The majority of Hurricane Ian restoration

costs were charged against Tampa Electric’s

FPSC approved storm reserve, resulting in minimal impact

to earnings for 2022. The total cost of restoration was $126 million USD, with approximately $119 million

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

the reserve balance and have been deferred as a regulatory asset for future recovery. On January 23,

2023, Tampa

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

replenishment of the balance in the reserve to the previous approved reserve level of $56 million USD, for

a total of approximately $131 million USD.

The proposed changes will be decided by the FPSC in March

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

The mid-course fuel adjustment requested by Tampa Electric on January 19, 2022, was approved on

March 1, 2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel

and capacity costs of $169 million USD and was spread over customer bills from April 1, 2022 through

December 2022.

In 2023, capital investment in the Florida Electric Utility segment is expected to be $1.3 billion USD (2022

– $1.1 billion USD), including allowance for funds used during construction (“AFUDC”). Capital projects

include solar investments,

grid modernization and storm hardening investments.

Canadian Electric Utilities

Canadian Electric Utilities includes NSPI and ENL. NSPI is a vertically integrated regulated electric utility

engaged in the generation, transmission and distribution of electricity and the primary electricity supplier

to customers in Nova Scotia. ENL is a holding company with equity investments in NSPML and LIL: two

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

Muskrat Falls on the Lower Churchill River in Labrador.

NSPI

With $6.8 billion of assets and approximately 541,000 customers, NSPI owns 2,420 MW of generating

capacity, of which approximately 44 per cent is coal-fired; 28 per cent is natural gas and/or oil; 19 per

cent is hydro and wind; 7 per cent is petcoke and 2 per cent is biomass-fueled generation. In addition,

NSPI has contracts to purchase renewable energy from independent power producers (“IPPs”), which

own 546 MW of capacity. NSPI also has rights to 153 MW of Maritime Link capacity,

representing Nalcor

Energy’s (“Nalcor”) Nova Scotia Block (“NS Block”) delivery obligations,

as discussed below. NSPI owns

approximately 5,000 kilometres of transmission facilities and 28,000 kilometres of distribution facilities.

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

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

NSPI anticipates earning near the low end of its allowed ROE range in 2023, and below the allowed

range in 2024. NSPI expects earnings and sales volumes to be higher in 2023 than 2022.

NSPI operated under a three-year fuel stability plan which resulted in an average annual overall rate

increase of 1.5 per cent to recover fuel costs for the period of 2020 through 2022. These rates include

recovery of Maritime Link costs (discussed below in the “ENL, NSPML” section).

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

(amended)”. The legislation limits non-fuel rate increases in NSPI’s 2022 General Rate Application

(“GRA”) to the UARB, excluding increases relating to demand side management (“DSM”) costs, to a total

of 1.8 per cent between the effective date of the UARB’s decision and the end of 2024. The legislation

also:

●

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

reliability of service to ratepayers,

●

limits NSPI’s return on equity to 9.25 per cent and equity ratio to 40 per cent, and

●

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

interest rate plus 1.75 per cent, unless otherwise directed by the UARB.

Actions required to address the impact of Bill 212, “Public Utilities Act (amended)”, include a material

reduction in NSPI’s planned capital investments and operating costs over the 2023 through 2024 period.

Such deferral of capital investment and operating costs may result in higher customer costs in future

periods. The legislation will have a direct and negative impact on the financial performance of NSPI and

has had a negative impact on NSPI’s credit quality. For more information on this risk, refer to the “Risk

Management and Financial Instruments – Regulatory and Political Risk” section.

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

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

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

consistent with the amendments to the Public Utilities Act made under Bill 212, which included a 1.8 per

cent cap on non-fuel rate increases for 2023 and 2024. Bill 212, “Public Utilities Act (amended),” is

described further above. The NSPI Settlement Agreement also addresses the recovery of fuel costs over

the settlement period and establishes a DSM rider. This will result in a combined fuel and non-fuel rate

increase of 6.9 per cent each year for 2023 and 2024 and annualized incremental revenue (fuel and non-

fuel) of $105 million in 2023 and $115 million in 2024. In addition, any under or over recovery of fuel costs

will be addressed through the UARB’s established FAM process. NSPI’s ROE range will continue to be

8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity

component of up to 40 per cent. The NSPI Settlement Agreement also establishes a storm rider for each

of 2023, 2024 and 2025, which gives NSPI the option to apply to the UARB for recovery of costs if major

storm restoration expense exceeds approximately $10 million in a given year. On February 2, 2023, NSPI

received the UARB’s decision, which substantially approved the NSPI Settlement Agreement as filed.

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

On September 24, 2022, Nova Scotia was struck by Hurricane Fiona, which made landfall as a post-

tropical storm equivalent to a Category 2 hurricane. The storm had sustained winds of over 100

kilometres per hour and peak gusts of approximately 180 kilometres per hour. This historic storm for Nova

Scotia caused significant and widespread damage to NSPI’s transmission and distribution system and at

the height of the storm approximately 415,000 customers lost power. The total cost of the restoration was

approximately $115 million, of which $91 million was capitalized to Property,

plant and equipment

(“PP&E”) and $24 million deferred to Other long-term assets for future amortization, subject to UARB

approval. NSPI intends to submit an application to the UARB requesting to defer the recognition of

incremental operating costs related to storm restoration. If the deferral is approved, this balance will be

reclassified to “Regulatory assets” and amortized over the UARB approved recognition period.

Energy from renewable sources has increased with Nalcor’s NS Block delivery obligations from the

Muskrat Falls hydroelectric project (“Muskrat Falls”) commencing in 2021. Nalcor is obligated to provide

NSPI with approximately 900 GWh of energy annually over 35 years. In addition, for the first five years of

the NS Block, Nalcor is obligated to provide approximately 240 GWh of additional energy from the

Supplemental Energy Block transmitted through the Maritime Link. Nalcor’s final commissioning of the LIL

has experienced delays and it’s expected that final commissioning of the LIL will be completed in 2023.

During these final stages of commissioning, there will be interruptions in supply, with any resultant

delivery shortfalls being delivered on a timely basis in accordance with the Energy and Capacity

Agreement. NSPI has the option of purchasing additional market-priced energy from Nalcor through the

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

from Nalcor for up to 1.8 Terawatt hours (“TWh”) of energy in any given year and, on average, 1.2 TWh of

energy per year through August 31, 2041.

Capital investment for 2023, including AFUDC, is expected to be approximately $375 million (2022 –

$540 million). NSPI is primarily investing in capital projects required to support power system reliability

and reliable service for customers.

Environmental Legislation and Regulations

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

Province of Nova Scotia. NSPI continues to work with both levels of government to comply with these

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

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

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

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

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

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

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

Nova Scotia Cap-and-Trade Program Regulations:

NSPI is a participant in the Nova Scotia Cap-and-Trade Program (“Cap-and-Trade Program”) and is

subject to the 2019 through 2022 compliance period. NSPI received granted emissions allowances under

the Cap-and-Trade Program and is permitted to purchase up to five per cent of the credits available at

provincial auctions. Any remaining allowance shortfall requires the purchase of reserve credits directly

from the provincial government, which are anticipated to be priced at a premium to provincial auction

pricing. Compliance is forecast to be achieved through granted emissions allowances and credit

purchases under the Cap-and-Trade Program, including reserve credits. Lower than forecast Muskrat

Falls energy received during the compliance period has resulted in the increased deployment of higher

carbon-emitting generation sources. The Province of Nova Scotia has agreed to provide approximately

$165 million of relief from the 2019 through 2022 compliance costs, which was equal to the total cost of

compliance forecast at the time of the fuel update submitted by NSPI to the UARB in September 2022 as

part of the GRA. Discussions related to the final amount of relief and how this relief will be provided are

ongoing. Further, NSPI’s regulatory framework provides for the recovery of costs prudently incurred to

comply with the Cap-and-Trade Program Regulations pursuant to NSPI’s FAM.

Carbon Pricing Regulations:

On November 9, 2022, the Nova Scotia provincial government enacted Bill 208, “Environment Act

(amended)”. The legislation provides the framework for Nova Scotia’s system to comply with the federal

government’s 2023 through 2030 carbon pollution pricing regulations laid out in the Pan-Canadian

Framework on Clean Growth and Climate Change. Nova Scotia’s proposed system utilizes an output-

based pricing system that will implement performance standards for large industrial greenhouse gas

emitters to achieve emission reduction goals. Subsequent regulations will be required to detail how the

pricing system will operate. The Province of Nova Scotia’s proposed output-based pricing system is

subject to the approval of the federal government. If an agreement is not reached between the federal

and provincial governments on a Nova Scotia system that meets the federal compliance criteria, Nova

Scotia will be subject to the federal carbon pollution pricing backstop which uses emissions performances

standards that vary by fuel type, and a carbon price that will start at $65 per tonne in 2023 and increase

by $15 per tonne annually, reaching $170 per tonne by 2030. NSPI’s regulatory framework provides for

the recovery of costs prudently incurred to comply with carbon pricing programs pursuant to NSPI’s FAM.

Nova Scotia Renewable Energy Regulations:

Under the provincially legislated Renewable Energy Regulations, 40 per cent of electric sales must be

generated from renewable sources. This standard was predicated on receipt of the full NS Block. Due to

the delay of the NS Block, the provincial government provided NSPI with an alternative compliance plan

that requires NSPI to achieve 40 per cent of electric sales generated from renewable sources over the

2020 through 2022 period. With delivery of the NS Block commencing later than anticipated, as well as

further interruptions in supply due to delays in the LIL, NSPI did not achieve the requirements of the

alternative compliance plan. The Renewable Energy Regulations require NSPI to have acted in a duly

diligent manner. If NSPI is found not to have acted in a duly diligent manner, it could be subject to a

maximum penalty of $10 million.

ENL

Total

equity earnings from NSPML and LIL are expected to be higher in 2023, compared to 2022. Both

the NSPML and LIL investments are recorded as “Investments subject to significant influence” on

Emera’s Consolidated Balance Sheets.

NSPML

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

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

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

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

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

efficiency and reliability of energy in both provinces. Nalcor continues to advance towards completion of

the LIL, and it’s expected final commissioning will be achieved in 2023. Nalcor’s NS Block delivery

obligations commenced on August 15, 2021, and the NS Block will be delivered over the next 35 years

pursuant to the project agreements. As Nalcor is in the final stages of commissioning the LIL, there will be

commissioning related interruptions in supply with any resultant delivery shortfalls being delivered on a

timely basis in accordance with the Energy and Capacity Agreement.

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

base of approximately $1.8 billion less $9 million of costs ($7 million after-tax) that would not have

otherwise been recoverable if incurred by NSPI. NSPML also received approval to collect up to $168

million (2021 – $172 million) from NSPI for the recovery of costs associated with the Maritime Link in

2022. This was subject to a holdback of up to $2 million per month, beginning April 2022, contingent on

receiving at least 90 per cent of NS Block deliveries, including Supplemental Energy deliveries.

In December 2022, NSPML received UARB approval to collect up to $164 million from NSPI for the

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

up to $2 million a month, as discussed above. On December 22, 2022, the UARB clarified its earlier

direction regarding the holdback and NSPI can now release the holdback to NSPML when 90 per cent of

NS Block deliveries, including Supplemental

Energy deliveries, is achieved. This enabled NSPI to pay

NSPML approximately $4 million of the 2022 holdback. As of December 31, 2022, an additional $14

million in aggregate has been held back by NSPI. Determination of allocation of the $14 million between

NSPML and NSPI will be subject to a regulatory process that is expected to commence in early 2023 to

review the holdback mechanism.

NSPML does not anticipate any significant capital investment in 2023.

LIL

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

will achieve final commissioning in 2023.

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

approved ROE. Emera’s current equity investment is $740 million, comprised of $410 million in equity

contribution and $330 million of accumulated equity earnings. Emera’s total equity contribution in the LIL,

excluding accumulated equity earnings, is estimated to be approximately $650 million after the Lower

Churchill projects are completed.

Cash earnings and return of equity will begin after commissioning of the LIL by Nalcor, which is

anticipated in 2023, and until that point Emera will continue to record AFUDC earnings.

Gas Utilities and Infrastructure

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

consolidated investment in M&NP.

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

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

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

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

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

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

Peoples Gas System

With $2.5 billion USD of assets and approximately 468,000 customers, the PGS system includes 24,300

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

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

2022.

The approved ROE range for PGS is 8.9 per cent to 11.0 per cent, based on an allowed equity capital

structure of 54.7 per cent. An ROE of 9.9 per cent is used for the calculation of return on investments for

clauses.

New Mexico Gas Company, Inc.

With $2.0 billion USD of assets and approximately 545,000 customers, NMGC’s system includes

approximately 2,426 kilometres of transmission pipelines and 17,781 kilometres of distribution pipelines.

Annual natural gas throughput was approximately 926 million therms in 2022.

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

Gas Utilities and Infrastructure Outlook

Gas Utilities and Infrastructure USD earnings are anticipated to be higher in 2023 than 2022, primarily

due to a base rate increase at NMGC, effective January 2023.

PGS expects 2023 rate base growth and USD earnings to be consistent with 2022 as higher revenues

from customer growth offset increased interest expenses and the effect of inflation. Increased residential

and commercial sales volumes and customer growth are anticipated in 2023. PGS anticipates earning

below its allowed ROE range in 2023 primarily due to rate base growth.

As a result, on February 3, 2023,

PGS notified the FPSC that it is planning to file a base rate proceeding in April 2023 for new rates

effective January 2024.

The PGS rate case settlement, which was approved in November 2020, provides the ability to reverse a

total of $34 million USD of accumulated depreciation through 2023. Through December 31, 2022, PGS

reversed $14 million USD accumulated depreciation. The reversal of the remaining accumulated

depreciation is expected to occur over 2023.

NMGC expects 2023 rate base and USD earnings to be higher in 2023 than 2022 due to base rate

increases effective January 2023, as discussed below, and rate base growth to expand the distribution

system and to continue to reliably serve customers. NMGC anticipates earning near its authorized ROE

in 2023 and expects customer growth rates to be consistent with historical trends. NMGC’s asset

optimization revenues for 2022 were well above the historical average, and may not recur in 2023.

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

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

an increase of $19 million USD in annual base revenues. The rates reflect the recovery of increased

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

settlement agreement on November 30, 2022.

In 2018, SeaCoast executed a 34-year agreement to provide long-term firm gas transportation service via

a 21-mile, 30-inch pipeline lateral. The lease of the pipeline lateral commenced January 1, 2022.

In 2023, capital investment in the Gas Utilities and Infrastructure segment is expected to be

approximately $475 million USD (2022 – $436 million USD), including AFUDC. PGS will make

investments to expand its system and support customer growth. NMGC will continue to make investments

to maintain the reliability of its system and support customer growth.

Other Electric Utilities

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

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

BLPC on the island of Barbados, GBPC on Grand Bahama Island, and a 19.5 per cent interest in Lucelec

on the island of St. Lucia, which is accounted for on the equity basis.

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

Services Ltd. (“Domlec”) for proceeds which approximated carrying value. Domlec was included in the

Other Electric Utilities segment in Q1 2022. The sale did not have a material impact on earnings.

BLPC

With $505 million USD of assets and approximately 133,000 customers, BLPC owns 276 MW of

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

BLPC owns approximately

188 kilometres of transmission facilities and 3,789 kilometres of distribution facilities. BLPC’s approved

regulated return on rate base for 2022 was 10 per cent.

GBPC

With $338 million USD of assets and approximately 19,000 customers, GBPC owns 98 MW of oil-fired

generation, approximately 90 kilometres of transmission facilities and 670 kilometres of distribution

facilities. GBPC’s approved regulatory return on rate base for 2023 is 8.32 per cent (2022 – 8.23 per

cent).

Other Electric Utilities Outlook

Absent the impact of the GBPC impairment charge in Q4 2022, Other Electric Utilities’ USD earnings in

2023 are expected to increase over the prior year primarily as a result of higher earnings due to higher

base rates at BLPC.

BLPC currently operates pursuant to a franchise to generate, transmit and distribute electricity on the

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

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

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

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

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

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

with the remaining licenses having terms ranging from 25-30 years. BLPC anticipates that any increased

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

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

the licenses once received.

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 toward 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 $23

million USD upon approval. The application includes a request for an allowed regulatory ROE of 12.50

per cent on an allowed equity capital structure of 65 per cent. On September 16,

2022, the FTC granted

BLPC interim rate relief, allowing an increase in base rates of approximately $3 million USD for the

remainder of 2022 and approximately $1 million USD per month for 2023. Interim rate relief is effective

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

On February 15, 2023, the FTC issued a decision on the BLPC rate review application which included the

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

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

to establish regulatory liabilities of approximately $70 million USD related to the self-insurance fund,

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

determinable but management does not expect the decision to have a material impact on Emera’s

adjusted net income. BLPC will seek to clarify aspects of the FTC decision in its compliance filing and is

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

final rates from the FTC in 2023.

On January 14, 2022, the GBPA issued its decision on GBPC’s rate application. The decision, which

became effective April 1, 2022, allows for an increase in revenues of $3.5 million USD. The new rates

include a regulatory ROE of 12.84 per cent.

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

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

monthly, in-line with actual fuel costs.

In 2023, capital investment in the Other Electric Utilities segment is expected to be approximately $65

million USD (2022 – $48 million USD), primarily in more efficient and cleaner sources of generation,

including renewables and battery storage.

Other

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

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

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

Business operations in the Other segment include Emera Energy and Emera Technologies LLC (“ETL”).

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

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

hydroelectric facility in northwestern Massachusetts. ETL is a wholly owned technology company focused

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

Corporate items included in the Other segment are certain corporate-wide functions including executive

management, strategic planning, treasury services, legal, financial reporting, tax planning, corporate

business development, corporate governance, investor relations, risk management, insurance, acquisition

and disposition related costs, gains or losses on select assets sales, and corporate human resource

activities. It includes interest revenue on intercompany financings and interest expense on corporate debt

in both Canada and the United States. It also includes costs associated with corporate activities that are

not directly allocated to the operations of Emera’s subsidiaries and investments.

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

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

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

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

annual adjusted net income within its guidance range of $15 to $30 million USD ($45 to $70 million USD

of margin).

Absent the TGH award in Q4 2022, the adjusted net loss from the Other segment is expected to be

higher in 2023, based on EES returning to its normal earnings range in 2023 and increased interest

expense. The increase is expected to be partially offset by decreased taxes due to a higher net loss.

The Other segment does not anticipate any significant capital investment in 2023.

CONSOLIDATED

BALANCE SHEET HIGHLIGHTS

Significant changes in the Consolidated Balance Sheets between December 31, 2021 and December 31,

2022 include:

millions of dollars

Increase

(Decrease)

Explanation

Assets

Cash and cash equivalents

(84)

Decreased due to increased investment in PP&E at regulated

utilities and dividends on common stock. These were partially

offset by proceeds from short-term debt issuance at Emera and

Tampa Electric, increased proceeds under committed credit

facilities at NSPI and Emera, cash from operations, and issuance

of common stock

Inventory

231

Increased due to higher commodity prices at Emera Energy and

NSPI, increased materials inventory at Tampa Electric and the

effect of the FX translation of Emera's foreign affiliates

Derivative instruments (current and

long-term)

Increased due to reversal of 2021 contracts at Emera Energy

Regulatory assets (current and long-

term)

1,054

Increased due to higher fuel cost recovery clauses at Tampa

Electric, increased FAM deferrals, driven mainly by increased

Cap-and Trade emissions compliance charges, and increased

deferred income tax regulatory assets at NSPI, the effect of the

FX translation of Emera's foreign affiliates, recognition of storm

reserve asset at Tampa Electric due to restoration costs from

Hurricane Ian in excess of the storm reserve liability, and

increased pension and post-retirement plan deferrals at Tampa

and NSPI. These were partially offset by recovery of gas costs

from the NMGC 2021 winter event

Receivables and other assets

(current and long-term)

1,165

Increased due to higher gas transportation assets and higher

trade receivables due to higher commodity prices at Emera

Energy, fuel option receivable at NMGC and the effect of the FX

translation of Emera's foreign affiliates

PP&E, net of accumulated

depreciation and amortization

2,643

Increased due to the effect of the FX translation of Emera's

foreign affiliates, and capital additions. These were partially offset

by reclassification of Seacoast's pipeline lateral on

commencement of the lease in 2022

Net investment in direct finance and

sales type leases

101

Increased due to commencement of the pipeline lease at

Seacoast in 2022

Goodwill

316

Increased due to the effect of the FX translation of Emera's

foreign affiliates, partially offset by the GBPC impairment

millions of dollars

Increase

(Decrease)

Explanation

Liabilities and Equity

Short-term debt and long-term debt

(including current portion)

2,644

Increased due to the effect of the FX translation of Emera's

foreign affiliates, issuance of short-term debt at Emera and

Tampa Electric, and net borrowings under the committed credit

facility at NSPI and Emera

Accounts payable

540

Increased due to increased commodity prices at Emera Energy,

Tampa Electric and NMGC, the effect

of the FX translation of

Emera's foreign affiliates, higher cash collateral position on

derivative instruments at NSPI, and timing of payments at Tampa

Electric and NSPI

Deferred income tax liabilities, net of

deferred income tax assets

386

Increased due to tax deductions in excess of accounting

depreciation related to PP&E, increase in net regulatory assets,

decrease in net derivative liabilities, and the effect of the FX

translation of Emera's foreign affiliates, partially offset by net

increase in tax loss carryforwards

Derivative instruments (current and

long-term)

396

Increased due to new contracts in 2022, partially offset by

reversal of 2021 contracts and changes in existing positions at

Emera Energy

Regulatory liabilities (current and

long-term)

218

Increased due to NMGC gas hedge settlements and the effect of

the FX translation of Emera's foreign affiliates, partially offset by

decreased storm reserve at Tampa Electric due to restoration

costs incurred from Hurricane Ian

Pension and post-retirement liabilities

(89)

Decreased due to favourable changes in actuarial assumptions,

partially offset by lower investment returns

Other liabilities (current and long-

term)

170

Increased due to accrued emissions compliance charges at NSPI

and the effect of the FX translation of Emera's foreign affiliates

Common stock

520

Increased due to Emera's ATM equity program and shares issued

under the DRIP

Accumulated other comprehensive

income

553

Increased due to the effect of the FX translation of Emera's

foreign affiliates

Retained earnings

236

Increased due to net income in excess of dividends paid.

OTHER DEVELOPMENTS

USGAAP Reporting Extension

Emera was granted exemptive relief by Canadian securities regulators on September 13, 2022, and

under the Companies Act (Nova Scotia) on October 12, 2022, each allowing Emera to continue to report

its financial results in accordance with USGAAP (collectively the “Exemptive Relief”). The Exemptive

Relief will terminate on the earliest of: (i) January 1, 2027; (ii) if the Company ceases to have rate-

regulated activities, the first day of the Company’s financial year that commences after the Company

ceases to have rate-regulated activities; and (iii) the first day of the Company’s financial year that

commences on or following the later of: (a) the effective date prescribed by the International Accounting

Standards Board (“IASB”) for the mandatory application of a standard within IFRS specific to entities with

rate-regulated activities (“Mandatory Rate-regulated Standard”); and (b) two years after the IASB

publishes the final version of a Mandatory Rate-regulated Standard. The Exemptive Relief replaces

similar relief that had been granted to Emera in 2018 and would have expired by no later than January 1,

2024.

Increase in Common Dividends

On September 22, 2022, the Emera Board of Directors approved an increase in the annual common

share dividend rate to $2.76 from $2.65. The first payment was effective November 15, 2022. Emera also

extended its dividend growth rate target of four to five per cent through 2025.

Appointments

Effective July 1, 2022, Michael Barrett was appointed Executive Vice President and General Counsel for

Emera. Mr. Barrett was most recently the General Counsel for Emera.

Effective June 30, 2022, Bruce Marchand was appointed Chief Risk and Sustainability Officer for Emera.

Mr. Marchand was most recently the Chief Legal and Compliance Officer for Emera.

FINANCIAL HIGHLIGHTS

Florida Electric Utility

All amounts are reported in USD, unless otherwise stated.

Three months ended

Year ended

For the

December 31

millions of USD (except as indicated)

2022

2021

2022

2021

Operating revenues – regulated electric

597

561

2,523

2,174

Regulated fuel for generation and purchased power

201

212

832

713

Contribution to consolidated net income

458

369

Contribution to consolidated net income – CAD

124

596

462

Average fuel costs in dollars per MWh

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

December 31, 2022, by $10 million and $23 million, respectively.

Net Income

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

For the

Three months ended

Year ended

millions of USD

December 31

Contribution to consolidated net income – 2021

369

Increased operating revenues due to higher rates effective January

2022, higher fuel recovery clause revenue as a result of increased fuel

costs, and customer growth. Year-over-year also increased due to

favourable weather

349

Fuel for generation and purchased power decreased in Q4 due to

lower natural gas prices quarter-over-quarter. Year

-over-year, fuel

increased due to higher natural gas prices

(119)

Increased OM&G due to timing of deferred clause recoveries. Year-

over-year the increase is also due to higher transmission and

distribution costs, higher benefit costs and higher insurance costs

(6)

(52)

Increased depreciation and amortization due to additions to facilities

and the in-service of generation projects

(5)

(15)

Increased interest expense due to higher interest rates and higher

borrowings to support Tampa Electric’s ongoing operations, including

fuel under-recoveries, and capital investments

(16)

(32)

Decreased AFUDC earnings due to timing of Big Bend modernization

and solar projects

(4)

(10)

Increased income tax expense year-over-year primarily due to

increased income before provision for income taxes

(36)

Other

Contribution to consolidated net income – 2022

458

Operating Revenues – Regulated Electric

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

Electric Revenues

Electric Sales Volumes

(millions of USD)

(Gigawatt hours ("GWh"))

2022

2021

2022

2021

Residential

1,381

1,156

10,109

9,941

Commercial

666

602

6,300

6,144

Industrial

176

172

2,111

2,122

Other

(1)

300

244

2,352

2,000

Total

2,523

2,174

20,872

20,207

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

to clauses.

Regulated Fuel for Generation and Purchased Power

Annual production volumes are summarized in the following table:

Production Volumes (GWh)

2022

2021

Natural gas

17,083

16,142

Purchased power

1,685

2,301

Solar

1,492

1,252

Coal

1,325

1,342

Total

21,585

21,037

Tampa

Electric’s fuel costs are affected by commodity prices and generation mix that is largely

dependent on economic dispatch of the generating fleet, bringing the lowest cost options on first

(renewable energy from solar), such that the incremental cost of production increases as sales volumes

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

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

environmental standards and regulations.

Regulatory Environment

Tampa

Electric is regulated by the FPSC and is also subject to regulation by the FERC. The FPSC sets

rates at a level that allows utilities such as Tampa Electric to collect total revenues or revenue

requirements equal to their cost of providing service, plus an appropriate return on invested capital. Base

rates are determined in FPSC rate setting hearings which can occur at the initiative of Tampa Electric, the

FPSC or other interested parties. For further details on Tampa Electric’s

regulatory environment, base

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

Canadian Electric Utilities

Three months ended

Year ended

For the

December 31

millions of dollars (except as indicated)

2022

2021

2022

2021

Operating revenues – regulated electric

421

389

1,675

1,501

Regulated fuel for generation and purchased power

(1)

173

263

950

817

Contribution to consolidated adjusted net income

222

241

NSPML unrecoverable costs

(7)

Contribution to consolidated net income

215

241

Average fuel costs in dollars per MWh

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

and fixed cost deferrals on the Consolidated

Statements of Income, however it is excluded in the segment overview.

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

table:

Three months ended

Year ended

For the

December 31

millions of dollars

2022

2021

2022

2021

NSPI

131

141

Equity investment in LIL

Equity investment in NSPML

(1)

Contribution to consolidated adjusted net income

222

241

(1) Excludes $7 million in NSPML unrecoverable costs, after-tax, for the year ended December 31, 2022 (2021 – nil).

Net Income

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

For the

Three months ended

Year ended

millions of dollars

December 31

Contribution to consolidated net income – 2021

241

Increased operating revenues due to increased electric revenues related

to recovery of fuel costs from an industrial customer, increased

residential and commercial class sales volumes, and increased

electricity pricing effective January 1, 2022. Quarter-over-quarter

increase partially offset by unfavourable weather

174

Decreased regulated fuel for generation and purchased power quarter-

over-quarter due to lower Cap-and-Trade Program provision and lower

Maritime Link assessment costs. Increased regulated fuel for generation

and purchased power year-over year due to increased Nova Scotia

Cap-and-Trade program provision, increased commodity prices and

higher sales volume, partially offset by a favourable change in

generation mix

(133)

Decreased FAM and fixed cost deferrals year-over-year due to

increased recovery of fuel costs, partially offset by increased Cap-and-

Trade provision. Quarter-over-quarter decreased due to increased

recovery of fuel costs and decreased Cap-and-Trade provision

(120)

(16)

Increased OM&G due to higher costs for storm restoration, IT, power

generation, and regulatory affairs

(20)

(47)

Increased depreciation and amortization due to increased PP&E in-

service

(5)

(13)

Decreased income tax expense primarily due to increased tax

deductions in excess of accounting depreciation and amortization

related to PP&E and deferrals and decreased income before provision

for income taxes. This was partially offset by the benefit of tax loss

carryforwards recognized as a deferred income tax regulatory liability

Year-over-year decrease in net income from equity investment in

NSPML primarily due to the Maritime Link holdback

(2)

(13)

NSPML unrecoverable costs

(7)

Other

(3)

Contribution to consolidated net income – 2022

215

NSPI

Operating Revenues – Regulated Electric

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

Electric Revenues

Electric Sales Volumes

(millions of dollars)

(GWh)

2022

2021

2022

2021

Residential

834

797

4,822

4,661

Commercial

427

407

3,006

2,902

Industrial

353

237

2,480

Other

148

153

Total

1,642

1,468

10,456

10,196

Regulated Fuel for Generation and Purchased Power

Annual production volumes are summarized in the following table:

Production Volumes (GWh)

2022

2021

Coal

3,771

4,623

Natural gas

1,650

1,673

Purchased power – other

910

865

Petcoke

897

519

Oil

251

Total non-renewables

7,479

7,761

Purchased power

2,423

1,977

Wind and hydro

1,105

1,007

Biomass

127

160

Total renewables

3,655

3,144

Total production volumes

11,134

10,905

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

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

renewable energy from IPPs, including Community Feed-in Tariff (“COMFIT”) participants, for which NSPI

has power purchase agreements in place, and the NS Block of energy, including the Supplemental

Energy Block. NSPI pays annual assessments approved by the UARB to NSPML for use of the Maritime

Link, and therefore utilizes all transmitted NS Block and Supplemental Energy Block energy received

which carries no additional fuel cost.

NSPI-owned hydro and wind have no fuel cost component. After hydro and wind, historically, petcoke and

coal have the lowest per-unit fuel cost, followed by natural gas. Oil, biomass and purchased power have

the next lowest fuel cost, depending on the relative pricing of each. Generation mix may also be affected

by plant outages, availability of renewable generation, availability of energy from the NS Block, plant

performance, and compliance with environmental standards including the Cap-and-Trade Program.

The generation mix has undergone significant transformation with the addition of non-dispatchable

renewable energy sources such as wind, including from IPPs and COMFIT, which typically have a higher

cost per MWh than NSPI-owned generation or other purchased power sources.

The provision for the Cap-and-Trade program was an $18 million recovery for the three months ended

December 31, 2022 (2021 - $35 million expense) and a $134 million expense for the year ended

December 31, 2022 (2021 - $38 million expense). For further information on this non-cash accrual, the

estimated costs and the FAM regulatory balance, refer to note 7 in the consolidated financial statements.

Regulatory Environment - NSPI

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

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

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

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

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

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

Gas Utilities and Infrastructure

All amounts are reported in USD, unless otherwise stated.

Three months ended

Year ended

For the

December 31

millions of USD (except as indicated)

2022

2021

2022

2021

Operating revenues – regulated gas

(1)

372

307

1,296

1,006

Operating revenues – non-regulated

Total operating revenue

374

309

1,308

1,018

Regulated cost of natural gas

181

139

614

375

Contribution to consolidated net income

170

157

Contribution to consolidated net income – CAD

221

198

(1) Operating revenues – regulated gas includes $13 million of finance income from Brunswick Pipeline (2021 – $12 million)

for the

three months ended December 31, 2022 and $47 million (2021 – $46 million) for the year ended December 31 2022;

however, it is

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

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

table:

Three months ended

Year ended

For the

December 31

millions of USD

2022

2021

2022

2021

PGS

NMGC

Other

Contribution to consolidated net income

170

157

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

December 31, 2022, by $4 million and $6 million, respectively.

Net Income

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

For the

Three months ended

Year ended

millions of USD

December 31

Contribution to consolidated net income – 2021

157

Increased gas revenues due to higher purchased gas adjustment

clause revenues at NMGC and PGS as a result of higher gas prices,

higher off-system sales, and customer growth at PGS

280

Increased asset optimization revenues at NMGC. In 2022, NMGC’s 30

per cent share of asset optimization revenues were well above the

historical average, and may not reoccur in 2023

Increased cost of natural gas sold due to higher gas prices at NMGC

and PGS, and higher off-system sales at PGS

(42)

(239)

Increased OM&G primarily due to higher labour and benefits costs at

NMGC and PGS, and higher contractor costs at PGS

(3)

(22)

Increased depreciation and amortization due to asset growth at PGS

and NMGC. Year-over-year,

the increase was more than offset by the

reversal of accumulated depreciation as a result of the rate case

settlement at PGS

(2)

Increased interest expense due to higher interest rates

(4)

(10)

Increased income tax expense primarily due to increased income

before provision for income taxes

(2)

(7)

Other

(3)

(5)

Contribution to consolidated net income – 2022

170

Operating Revenues – Regulated Gas

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

Gas Revenues

Gas Volumes

(millions of USD)

(Therms)

2022

2021

2022

2021

Residential

614

510

421

405

Commercial

354

301

836

799

Industrial

(1)

1,429

1,434

Other

(2)

217

227

137

Total

(3)

1,249

960

2,913

2,775

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

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

(3) Total gas revenue

excludes $47 million of finance income from Brunswick Pipeline (2021 – $46 million).

Regulated Cost of Natural Gas

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

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

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

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

customers.

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

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

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

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

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

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

Gas Volumes by Type (millions of Therms)

2022

2021

Transportation

2,206

2,154

System supply

707

621

Total

2,913

2,775

Regulatory Environments

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

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

on invested capital.

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

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

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

note 7 in the consolidated financial statements.

Other Electric Utilities

All amounts are reported in USD, unless otherwise stated.

Three months ended

Year ended

For the

December 31

millions of USD (except as indicated)

2022

2021

2022

2021

Operating revenues – regulated electric

398

355

Regulated fuel for generation and purchased power

223

175

Contribution to consolidated adjusted net income

Contribution to consolidated adjusted net income – CAD

GBPC Impairment charge

Equity securities MTM gain (loss)

(4)

Contribution to consolidated net income

(46)

(35)

Contribution to consolidated net income – CAD

(62)

(48)

Electric sales volumes (GWh)

301

330

1,239

1,262

Electric production volumes (GWh)

336

357

1,340

1,359

Average fuel cost in dollars per MWh

161

146

166

129

The impact of the change in the FX rate increased net loss by $3 million for the three months and year

ended December 31, 2022 and had a minimal impact on adjusted net income for the same periods.

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

table:

Three months ended

Year ended

For the

December 31

millions of USD

2022

2021

2022

2021

BLPC

GBPC

Other

(2)

(3)

Contribution to consolidated adjusted net income

Net Income

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

For the

Three months ended

Year ended

millions of USD

December 31

Contribution to consolidated net income – 2021

Increased operating revenues - regulated electric year-over-year due to

higher fuel revenue at BLPC as a result of higher fuel prices, partially

offset by the sale of Domlec in Q1 2022

Increased fuel for generation and purchased power as a result of

higher fuel prices at BLPC

(2)

(48)

Decreased OM&G due to the sale of Domlec in Q1 2022 and lower

generation costs at GBPC, partially offset by the recognition of

Hurricane Dorian insurance proceeds at GBPC in 2021

Goodwill impairment charge at GBPC

(54)

Decreased MTM gain on equity securities held in BLPC

(1)

(5)

Other

(6)

(5)

Contribution to consolidated net income – 2022

(46)

(35)

Regulatory Environments

BLPC is regulated by the FTC, an independent regulator. Rates are set to recover prudently incurred

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

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

service to customers plus an appropriate return on rate base.

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

7 in the consolidated financial statements.

Other

Three months ended

Year ended

For the

December 31

millions of dollars

2022

2021

2022

2021

Marketing and trading margin

(1) (2)

143

102

Other non-regulated operating revenue

Total operating revenues – non-regulated

159

132

Contribution to consolidated adjusted net income (loss)

(1)

(44)

(218)

(198)

MTM gain (loss), after-tax

(3)

304

154

179

(214)

Contribution to consolidated net income (loss)

303

110

(39)

(412)

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

pipeline and storage capacity

costs and energy asset management services’ revenues.

(2) Marketing and trading margin excludes a MTM gain, pre-tax of $430 million in Q4 2022 (2021 – $212 million gain) and a gain

$281 million for the year ended December 31, 2022 (2021 – $289 million loss).

(3) Net of income tax expense of $124 million for the three months ended December 31, 2022 (2021 – $63 million expense)

and $73

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

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

Three months ended

Year ended

For the

December 31

millions of dollars

2022

2021

2022

2021

Emera Energy

Corporate – see breakdown of adjusted contribution below

(37)

(57)

(267)

(231)

Emera Technologies

(5)

(4)

(18)

(17)

Other

(3)

(4)

Contribution to consolidated adjusted net income (loss)

(1)

(44)

(218)

(198)

MTM Adjustments

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

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

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

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

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

chart below.

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

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

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

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

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

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

which is amortized over the term of the AMA contract.

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

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

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

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

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

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

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

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

Fluctuations in the FX rate result in MTM gains or losses recorded in income.

Net Income

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

For the

Three months ended

Year ended

millions of dollars

December 31

Contribution to consolidated net income (loss) – 2021

110

(412)

Increased marketing and trading margin due to weather driven market

conditions that increased pricing and volatility, which created profitable

opportunities for Emera Energy. Year

-over-year increase also reflected

sustained higher pricing and volatility

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

compensation and related hedges

(19)

(55)

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

and increased total debt

(17)

(27)

Increased FX loss, pre-tax, primarily due to realized gains in 2021 on

FX hedges entered into to hedge USD denominated operating unit

earnings exposure

(9)

(28)

Increased income tax recovery primarily due to increased losses before

provision for income taxes

Increased preferred stock dividends due to issuance of preferred

shares in 2021

(2)

(13)

TGH award, after tax and legal costs

Increased MTM gain, after-tax, due to change in existing positions and

larger reversal of MTM losses in 2022, partially offset by higher

amortization of gas transportation assets in 2022 at Emera Energy

150

393

Other

(8)

Contribution to consolidated net income (loss) – 2022

303

(39)

Emera Energy

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

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

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

transmission capacity rights, and provides energy asset management services. The primary market area

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

the Marcellus and Utica shale supply areas. EES also participates in the Florida, United States Gulf Coast

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

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

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

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

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

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

movement across its portfolio.

Corporate

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

Three months ended

Year ended

For the

December 31

millions of dollars

2022

2021

2022

2021

Operating expenses

(1)

Interest expense

291

264

Income tax recovery

(35)

(18)

(109)

(75)

Preferred dividends

TGH award, after tax and legal costs

(45)

Other

(2)(3)

(2)

(5)

(16)

(36)

Corporate adjusted net loss

(4)

(37)

(57)

(267)

(231)

(1) Operating expenses include OM&G and depreciation. In Q4 2021, OM&G and depreciation were offset by

a decrease in long-

term incentive compensation. The value of long-term incentive compensation and related hedges are impacted by changes

Emera's period end share price.

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

exposure.

(3) Includes a realized, pre-tax net loss of $5 million (2021 – $5 million gain) quarter-to-date and a $6 million

loss for the year ended

December 31, 2022 (2021 – $18 million gain) on FX hedges, as discussed above.

(4) Excludes a MTM gain, after-tax of $9 million for the three months ended December 31, 2022 (2021 – $3 million loss) and a MTM

loss, after-tax of $12 million for the year ended December 31, 2023 (2021 – $14 million loss)

LIQUIDITY AND CAPITAL RESOURCES

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

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

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

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

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

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

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

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

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

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

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

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

Emera has an $8 – 9 billion capital investment plan over the 2023-to-2025 period (including a $240 million

equity investment in the LIL in 2023), mainly focused in Florida. This plan includes significant rate base

investments across the portfolio in renewable and cleaner generation, infrastructure modernization and

customer-focused technologies. Capital investments at the regulated utilities are subject to regulatory

approval.

Emera plans to use cash from operations and debt raised at the utilities to support normal operations,

repayment of existing debt, and capital requirements. Debt raised at certain of the Company’s utilities is

subject to applicable regulatory approvals. Equity requirements in support of the Company’s capital

investment plan are expected to be funded through the issuance of preferred equity and the issuance of

common equity through Emera’s DRIP and ATM program.

Emera has credit facilities with varying maturities that cumulatively provide $4.7 billion of credit, with

approximately $1.1 billion undrawn and available at December 31, 2022. The Company was holding a

cash balance of $332 million at December 31, 2022. For further discussion, refer to the “Debt

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

and 25 in the consolidated financial statements.

Consolidated Cash Flow Highlights

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

31, 2022 and 2021 include:

millions of dollars

2022

2021

$ Change

Cash, cash equivalents and restricted cash, beginning of period

417

254

163

Provided by (used in):

Operating cash flow before changes in working capital

1,147

1,337

(190)

Change in working capital

(234)

(152)

(82)

Operating activities

913

1,185

(272)

Investing activities

(2,569)

(2,332)

(237)

Financing activities

1,555

1,311

244

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

(1)

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

332

417

(85)

Cash Flow from Operating Activities

Net cash provided by operating activities decreased

$272 million to $913 million for the year ended

December 31, 2022, compared to $1,185 million in 2021.

Cash from operations before changes in working capital decreased

$190 million for the year ended

December 31, 2022. This decrease was due to under-recovery of clause-related costs primarily due to

higher natural gas prices at Tampa Electric, unfavourable changes in Tampa

Electric’s storm reserve

balance as a result of Hurricane Ian, increased fuel for generation and purchased power at NSPI, and

decreased long-term payables due to the Nova Scotia Cap-and-Trade accrued emissions compliance

charges being reclassified to other current liabilities as the liability is anticipated to be settled in 2023.

This was partially offset by the 2021 deferral of gas costs at NMGC resulting from the extreme cold

weather event, increased revenues at Tampa Electric and NSPI, favourable changes in regulatory

liabilities due to the NMGC gas hedge settlement, TGH award, and increased marketing and trading

margin at Emera Energy.

Changes in working capital decreased operating cash flows by $82 million for the year ended December

31, 2022. This decrease was due to unfavourable changes in accounts receivable at NMGC due to the

gas hedge settlement, unfavourable changes in accounts receivable at NSPI, unfavourable changes in

cash collateral positions on derivative instruments at NSPI, and the required prepayment of income taxes

and related interest at NSPI. This was partially offset by the Nova Scotia Cap-and-Trade accrued

emissions compliance charges, favourable changes in cash collateral positions at Emera Energy, and

favourable changes in accounts payable at Tampa Electric and NMGC.

Cash Flow used in Investing Activities

Net cash used in investing activities increased $237 million to $2,569 million for the year ended

December 31, 2022, compared to $2,332 million in 2021. The increase was due to higher capital

investment in 2022.

Capital expenditures for the year ended December 31, 2022, including AFUDC, were $2,646 million

compared to $2,420 million in 2021. Details of 2022 capital spending by segment are shown below:

●

$1,481 million – Florida Electric Utility (2021 – $1,408 million);

●

$518 million – Canadian Electric Utilities (2021 – $374 million);

●

$578 million – Gas Utilities and Infrastructure (2021 – $522 million);

●

$63 million – Other Electric Utilities (2021 – $111

million); and

●

$6 million – Other (2021 – $5 million).

Cash Flow from Financing Activities

Net cash provided by financing activities increased $244 million to $1,555 million for the year ended

December 31, 2022, compared to $1,311 million in 2021. This increase was due to higher proceeds of

short-term debt at Tampa Electric, proceeds from committed credit facilities at NSPI, and term loan

issuance at Emera in 2022. These were partially offset by the issuance of preferred shares in 2021, lower

proceeds of long-term debt at Tampa Electric, and net proceeds of long-term debt at NMGC in 2021.

Working Capital

As at December 31, 2022, Emera’s cash and cash equivalents were $310 million (2021 – $394 million)

and Emera’s investment in non-cash working capital was $1,173 million (2021 – $491 million). Of the

cash and cash equivalents held at December 31, 2022, $250 million was held by Emera’s foreign

subsidiaries (2021 – $194 million). A portion of these funds are invested in countries that have certain

exchange controls, approvals, and processes for repatriation. Such funds are available to fund local

operating and capital requirements unless repatriated.

Contractual Obligations

As at December 31, 2022, contractual commitments for each of the next five years and in aggregate

thereafter consisted of the following:

millions of dollars

2023

2024

2025

2026

2027

Thereafter

Total

Long-term debt principal

574

1,613

262

3,110

946

9,937

16,442

Interest payment obligations

(1)

720

699

653

566

472

6,995

10,105

Transportation

(2)

693

516

423

383

367

2,817

5,199

Purchased power

(3)

269

243

237

228

243

2,145

3,365

Fuel, gas supply and storage

1,161

282

138

1,627

Capital projects

264

358

Asset retirement obligations

415

436

Pension and post-retirement

obligations

(4)

178

419

Equity investment commitments

(5)

240

Other

154

142

132

189

708

4,128

3,617

1,882

4,460

2,135

22,677

38,899

(1) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity.

For debt instruments

with variable rates, interest is calculated for all future periods using the rates in effect at December 31,

2022, including any expected

required payment under associated swap agreements.

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

Includes a commitment of

$144 million related to a gas transportation contract between PGS and SeaCoast through 2040.

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

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

funded

pension plans (excluding the possibility of wind-up), plus the estimated costs of further benefit accruals contracted under

NSPI's

Collective Bargaining Agreement and estimated benefit payments related to other unfunded benefit plans.

(5) Emera has a commitment to make a final equity contribution to the LIL upon its commissioning. Once commissioned, the

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

of the parties

in relation to the Maritime Link and LIL.

NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years

from its January 15, 2018 in-service date. In February 2022, the UARB issued its decision and Board

Order approving NSPML’s requested rate base of approximately $1.8 billion. In December 2022, the

UARB approved the collection of $164 million from NSPI for the recovery of Maritime Link costs in 2023.

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

subject to UARB approval.

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

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

transmit this energy from Nova Scotia to New England energy markets effective August 15, 2021, the

date the NS Block delivery obligation commenced, and continuing for 50 years. As transmission rights are

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

Forecasted Gross Consolidated Capital Expenditures

The 2023 forecasted gross consolidated capital expenditures are as follows:

millions of dollars

Florida

Electric

Utility

Canadian

Electric

Utilities

Gas Utilities

and

Infrastructure

Other

Electric

Utilities

Other

Total

Generation

276

120

432

New renewable generation

402

406

Transmission

100

174

Distribution

479

121

634

Gas transmission and distribution

639

Facilities, equipment, vehicles, and other

516

604

1,773

375

639

2,889

Debt Management

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

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

below.

Undrawn

Credit

and

millions of dollars

Maturity

Facilities

Utilized

Available

Emera – Unsecured committed revolving credit facility

June 2027

900

403

497

TEC (in USD) – Unsecured committed revolving credit facility

(1)

December 2026

800

620

180

NSPI – Unsecured committed revolving credit facility

December 2027

800

497

303

Emera – Unsecured non-revolving facility

December 2023

400

Emera – Unsecured non-revolving facility

August 2023

400

TEC (in USD) – Unsecured non-revolving facility

(2)

December 2023

400

TECO Finance (in USD) – Unsecured committed revolving credit

facility

December 2026

400

355

NSPI – Unsecured non-revolving facility

July 2024

400

NMGC (in USD) – Unsecured revolving credit facility

December 2026

125

NMGC (in USD) – Unsecured non-revolving facility

March 2024

Other (in USD) – Unsecured committed revolving credit facilities

Various

(1) This facility is available for use by Tampa

Electric and PGS. At December 31, 2022, $554 million USD was used by Tampa

Electric and $66 million USD was used by PGS.

(2) This facility is available for use by Tampa

Electric and PGS. At December 31, 2022, $300 million USD was used by Tampa

Electric and $100 million USD was used by PGS.

Emera and its subsidiaries have certain financial and other covenants associated with their debt and

credit facilities. Covenants are tested regularly, and the Company is in compliance with covenant

requirements as at December 31, 2022.

Emera’s significant covenant is listed below:

As at

Financial Covenant

Requirement

December 31, 2022

Emera

Syndicated credit facilities

Debt to capital ratio

Less than or equal to 0.70 to 1

0.57 : 1

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

Florida Electric Utilities

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

from December 16, 2022 to December 13, 2023 and reduced the facility amount from $500 million USD

to $400 million USD. There were no other significant changes in commercial terms from the prior

agreement.

On September 15, 2022, TEC repaid a $250 million USD note upon maturity. The note was repaid using

existing credit facilities.

On July 12, 2022, TEC completed an issuance of $600 million USD senior notes. The issuance included

$300 million USD senior notes that bear an interest rate of 3.875 per cent with a maturity date of July 12,

2024, and $300 million USD senior notes that bear an interest rate of 5 per cent with a maturity date of

July 15, 2052. Proceeds from the issuance were used to repay TEC’s $470 million USD commercial

paper, due in 2022, and for general corporate purposes.

Canadian Electric Utilities

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

from December 16, 2026 to December 16, 2027 and increase the amount of the facility from $600 million

to $800 million. There were no other significant changes in commercial terms from the prior agreement.

On July 15, 2022, NSPI entered into a $400 million non-revolving term credit facility which matures on

July 15, 2024. The credit facility contains customary representation and warranties, events of default and

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

margin. Proceeds from this facility were used for general corporate purposes.

Gas Utilities and Infrastructure

On September 23, 2022, NMGC amended its $80 million USD, unsecured, non-revolving term credit

facility to extend the maturity from September 23, 2022, to March 22, 2024. There were no other changes

in commercial terms from the prior agreement.

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

from June 30, 2025 to June 30, 2026. There were no other changes in commercial terms from the prior

agreement.

Other Electric Utilities

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

2022 to March 25, 2027. There were no other changes in commercial terms from the prior agreement.

Other

On December 16, 2022, Emera amended its $900 million revolving operating credit facility to extend the

maturity date from June 30, 2026 to June 30, 2027. There were no other significant changes in

commercial terms from the prior agreement.

On December 16, 2022, Emera amended its $400 million non-revolving term credit facility to extend the

maturity from December 16, 2022 to December 16, 2023. There were no other significant changes in

commercial terms from the prior agreement.

On August 2, 2022, Emera entered into a $400 million non-revolving term facility which matures on

August 2, 2023. The credit agreement contains customary representation and warranties, events of

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

advances, plus a margin. Proceeds from this facility were used for general corporate purposes.

Credit Ratings

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

Fitch

(1)

S&P

(2)(3)

Moody's

(4)(5)

DBRS

(6)

Emera Inc.

BBB (Negative)

BBB- (Negative)

Baa3 (Negative)

N/A

TECO Energy/TECO Finance

N/A

TEC

A (Negative)

BBB+ (Negative)

A3 (Negative)

N/A

NMGC

BBB+ (Negative)

N/A

NSPI

N/A

BBB- (Negative)

N/A

BBB (high)(stable)

(1) On November 21, 2022, Fitch Ratings ("Fitch") affirmed its BBB issuer rating for Emera Inc. Fitch also

affirmed the A- issuer and

A unsecured debt ratings for TEC and BBB+ for NMGC. Emera and subsidiaries’ outlook was changed to negative from stable.

(2) On November 21, 2022, S&P Global Ratings (“S&P”) affirmed its BBB issuer rating for Emera Inc. and TECO

Energy, while

affirming the BBB+ issuer credit ratings for TEC. S&P downgraded NSPI's issue-level and senior unsecured

debt ratings to BBB-.

Emera and subsidiaries’ outlook remained at negative.

(3) On October 24, 2022, S&P affirmed its BBB issuer rating for Emera Inc. S&P also affirmed

ratings on NSPI, TECO Energy, and

TEC affirming the BBB+ issuer credit ratings for NSPI and TEC. Emera and subsidiaries’ outlook was changed

to negative from

stable.

(4) On November 2, 2022, Moody’s Investor Services (“Moody’s”) affirmed

its Baa3 issuer rating for Emera Inc. Moody’s also

affirmed ratings on TECO Finance and TEC, affirming the TECO Finance Baa1 issuer

rating and A3 issuer rating for TEC. Emera

and subsidiaries’ outlook was changed to negative from stable.

(5) On June 2, 2022, Moody’s affirmed its Baa1 issuer rating for TECO Finance. Moody’s

also affirmed TEC’s A3 issuer rating and

changed the outlook to stable from positive.

(6) On December 20, 2022, DBRS (“Dominion Bond Rating Service”) downgraded its issuer credit and senior unsecured rating

for

NSPI to BBB (high). NSPI’s outlook remained unchanged at stable.

The downgrades from both S&P and DBRS of NSPI were attributed to their view of the enactment of Bill

212, “Public Utilities Act (amended)”, as a political intervention in the regulatory process that resulted in

an increase in political risk and a reduction in the stability and predictability of NSPI’s regulatory

environment.

Guaranteed Debt

As of December 31, 2022, the Company had $2.75 billion USD senior unsecured notes ("U.S. Notes”)

outstanding.

The U.S. Notes are fully and unconditionally guaranteed, on a joint and several basis, by Emera and

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

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

Other subsidiaries

of the Company do not guarantee the U.S. Notes (such subsidiaries are referred to as the "Non-

Guarantor Subsidiaries") however, Emera has unrestricted access to the assets of consolidated entities.

In compliance with Rule 13-01 of Regulation S-X, the Company is including summarized financial

information for Emera, Emera US Holdings Inc., and Emera US Finance LP (together, the "Obligor

Group"), on a combined basis after transactions and balances between the combined entities have been

eliminated. Investments in and equity earnings of the Non-Guarantor Subsidiaries have been excluded

from the summarized financial information.

The Obligor Group was not determined using geographic, service line or other similar criteria and, as a

result the summarized financial information includes portions of Emera’s domestic and international

operations. Accordingly, this basis of presentation is not intended to present Emera’s financial condition

or results of operations for any purpose other than to comply with the specific requirements for guarantor

reporting.

Summarized Statement of Income (loss)

The Company recognized income related to guaranteed debt under the following categories:

For the

Year ended December 31

millions of dollars

2022

2021

Loss from operations

(73)

(21)

Net losses

(1)

(131)

(86)

(1) Includes $262 million in interest and dividend income, net, from non-guarantor subsidiaries.

Summarized Balance Sheet

The Company has the following categories on the balance sheet related to guaranteed debt:

As at

December 31

millions of dollars

2022

2021

Current assets

(1)

172

329

Goodwill

6,012

5,628

Other assets

(2)

6,402

6,027

Total assets

(3)

12,586

11,984

Current liabilities

(4)

1,903

888

Long-term liabilities

(5)

6,431

6,403

Total liabilities

8,334

7,291

(1) Includes $144 million (2021 – $140 million) in amounts due from non-guarantor subsidiaries.

(2) Includes $6,058 million (2021 – $5,749 million) in amounts due from non-guarantor subsidiaries.

(3) Excludes investments in non-guarantor subsidiaries. Consolidated Emera total assets are $39,742 million

(2021 – $34,244

million).

(4) Includes $392 million (2021 – $346 million) due to non-guarantor subsidiaries.

(5) Includes $769 million (2021 – $776 million) due to non-guarantor subsidiaries.

Outstanding Stock Data

Common Stock

millions of

Issued and outstanding:

dollars

Balance, December 31, 2021

261.07

7,242

Issuance of common stock under ATM program

(1)

4.07

248

Issued under the DRIP,

net of discounts

4.21

238

Senior management stock options exercised and Employee Share Purchase Plan

0.60

Balance, December 31, 2022

269.95

7,762

(1)

In Q4 2022, 278,545 common shares were issued under Emera's ATM

program at an average price of $54.06 per share for

gross proceeds of $15 million ($15 million net of after-tax issuance costs). For the year ended December 31, 2022, 4,072,469

common shares were issued under Emera's ATM

program at an average price of $61.31 per share for gross proceeds of $250

million ($248 million net of after-tax issuance costs). As at December 31, 2022, an aggregate gross sales limit

of $207 million

remained available for issuance under the ATM program.

As at February 16, 2023, the amount of issued and outstanding common shares was 271.4 million.

If all outstanding stock options were converted as at February 16, 2023, an additional 2.9 million common

shares would be issued and outstanding.

Preferred Stock

As at February 16, 2023, Emera had the following preferred shares issued and outstanding: Series A –

4.9 million; Series B – 1.1 million; Series C – 10.0 million; Series E – 5.0 million; Series F – 8.0 million;

Series H – 12.0 million; Series J – 8.0 million, and Series L – 9.0 million. Emera’s preferred shares do not

have voting rights unless the Company fails to pay, in aggregate, eight quarterly dividends.

PENSION FUNDING

For funding purposes, Emera determines required contributions to its largest defined benefit pension

plans based on smoothed asset values. This reduces volatility in the cash funding requirement as the

impact of investment gains and losses are recognized over a three-year period. The cash required in

2023 for defined benefit pension plans is expected to be $44 million (2022 – $45 million). All pension plan

contributions are tax deductible and will be funded with cash from operations.

Emera’s defined benefit pension plans employ a long-term strategic approach with respect to asset

allocation, real return and risk. The underlying objective is to earn an appropriate return, given the

Company’s goal of preserving capital with an acceptable level of risk for the pension fund investments.

achieve the overall long-term asset allocation, pension assets are managed by external investment

managers per the pension plan’s investment policy and governance framework. The asset allocation

includes investments in the assets of Canadian and global equities, domestic and global bonds and short-

term investments. Emera reviews investment manager performance on a regular basis and adjusts the

plans’ asset mixes as needed in accordance with the pension plans’ investment policy.

Emera’s projected contributions to defined contribution pension plans are $44 million for 2023 (2022 –

$41 million).

Defined Benefit Pension Plan Summary

in millions of dollars

Plans by region

TECO Energy

NSPI

Caribbean

Total

Assets as at December 31, 2022

880

1,273

2,163

Accounting obligation at December 31, 2022

902

1,240

2,158

Accounting expense during fiscal 2022

(3)

Off-Balance Sheet Arrangements

Defeasance

Upon privatization in 1992, NSPI became responsible for managing a portfolio of defeasance securities

that provide principal and interest streams to match the related defeased debt, which at December 31,

2022 totalled $200 million (2021 – $200 million). The securities are held in trust for an affiliate of the

Province of Nova Scotia. Approximately 66 per cent of the defeasance portfolio consists of investments in

the related debt, eliminating all risk associated with this portion of the portfolio; the remaining defeasance

portfolio has a market value higher than the related debt, reducing the future risk of this portion of the

portfolio.

Guarantees and Letters of Credit

Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant

guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December

31, 2022:

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

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

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

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

the event 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 $27 million USD.

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

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

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

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

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

investment grade by Moody’s or S&P,

TECO Energy would need to provide either a substitute guarantee

from an affiliate with an investment grade credit rating or a letter of credit or cash deposit of $13 million

USD.

Emera Inc. has issued a guarantee of up to $35 million USD relating to outstanding notes of GBPC. The

guarantee for the notes will expire in May 2023.

Emera Inc. has issued a guarantee of $66 million USD relating to outstanding notes of ECI. This

guarantee will automatically terminate on the date upon which the obligations have been repaid in full.

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

(“NSPEMI”), in the amount of $119 million USD (2021 – $118

million USD) with terms of varying lengths.

The Company has standby letters of credit and surety bonds in the amount of $145 million USD

(December 31, 2021 – $148 million USD) to third parties that have extended credit to Emera and its

subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed

annually as required.

Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary

retirement plan. The expiry date of this letter of credit was extended to June 2023. The amount committed

as at December 31, 2022 was $63 million (December 31, 2021 – $64 million).

DIVIDEND PAYOUT

RATIO

Emera has provided annual dividend growth guidance of four to five per cent through 2025. The

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

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

return to that range over time. Emera’s common share dividends paid in 2022 were $2.6775 ($0.6625 in

Q1, Q2, and Q3 and $0.6900 in Q4) per common share and $2.5750 ($0.6375 in Q1, Q2, and Q3 and

$0.6625 in Q4) per common share for 2021, representing a dividend payout ratio of 75 per cent in 2022

(2021 – 129 per cent) and a dividend payout ratio of adjusted net income of 83 per cent in 2022 (2021 –

91 per cent).

On September 22, 2022, the Emera Board of Directors approved an increase in the annual common

share dividend rate to $2.76 from $2.65. The first quarterly dividend payment at the increased rate was

paid on November 15, 2022.

TRANSACTIONS WITH RELATED

PARTIES

In the ordinary course of business, Emera provides energy and other services and enters into

transactions with its subsidiaries, associates and other related companies on terms similar to those

offered to non-related parties. Intercompany balances and intercompany transactions have been

eliminated on consolidation, except for the net profit on certain transactions between non-regulated and

regulated entities in accordance with accounting standards for rate-regulated entities. All material

amounts are under normal interest and credit terms.

Significant transactions between Emera and its associated companies are as follows:

●

Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the

Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and

purchased power, totalling $157 million for the year ended December 31, 2022 (2021 – $149 million).

NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to

this revenue are reflected in Income from equity investments. For further details, refer to the

“Business Overview and Outlook - Canadian Electric Utilities – ENL” and “Contractual Obligations”

sections.

●

Natural gas transportation capacity purchases from M&NP are reported in the Consolidated

Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated,

totalled $9 million for the year ended December 31, 2022 (2021

– $19 million).

There were no significant receivables or payables between Emera and its associated companies reported

on Emera’s Consolidated Balance Sheets as at December 31, 2022 and at December 31, 2021.

ENTERPRISE RISK AND RISK MANAGEMENT

Emera has an enterprise-wide risk management process, overseen by its Enterprise Risk Management

Committee (“ERMC”) and monitored by the Board of Directors, to ensure an effective, consistent and

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

the ERMC to ensure such risks are appropriately identified, assessed, monitored and subject to

appropriate controls.

The Board 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. The RSC’s mandate includes oversight of the Company’s Enterprise Risk Management

framework, including the identification, assessment, monitoring and management of enterprise risks. It

also includes oversight of the Company’s approach to sustainability and its performance relative to its

sustainability objectives.

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

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

risk management focus

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

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

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

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

material may become material in the future.

Regulatory and Political Risk

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

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

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

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

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

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

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

As a regulated Group II pipeline, the tolls of

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

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

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

with Repsol Energy North America Canada Partnership. The agreement provides for a predetermined toll

increase in the fifth and fifteenth year of the contract.

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

rates and/or riders, the underlying allowed ROEs, deemed capital structures, capital investment, the

terms and conditions for the provision of service, performance standards, and affiliate transactions. Costs

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

and/or riders, which normally require a public hearing process or may be mandated by other

governmental bodies.

During public hearing processes, consultants and customer representatives

scrutinize the costs, actions and plans of these rate-regulated companies, and their respective regulators

determine whether to allow recovery and to adjust rates based upon the evidence and any contrary

evidence from other parties. In some circumstances, other government bodies may influence the setting

of rates. Regulatory decisions, legislative changes, and prolonged delays in the recovery of costs or

regulatory assets could result in decreased rate affordability for customers and could materially affect

Emera and its utilities.

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

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

operations, regulatory audits, rate filings and capital plans. The subsidiaries employ a collaborative

regulatory approach through technical conferences and, where appropriate, negotiated settlements.

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

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

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

may result in increased competition and unrecovered costs that could adversely affect operations, net

income and cash flows. State and local policies in some United States jurisdictions have sought to

prevent or limit the ability of utilities to provide customers the choice to use natural gas while in other

jurisdictions policies have been adopted to prevent limitations on the use of natural gas. Changes in

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

PGS and NMGC.

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

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

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

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

Global Climate Change Risk

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

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

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

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

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

Environmental Legislation” risk below. Insurance companies have begun to limit their exposure to coal-

fired electricity generation and are evaluating the medium and long-term impacts of climate change which

may result in fewer insurers, more restrictive coverage and increased premiums. Refer to the “Markets”

section below and “Uninsured Risk”.

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

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

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

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

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

temperatures may bring increased frequency and severity of wildfires within the Company’s service

territories. Refer to “Weather Risk” and “System Operating and Maintenance Risks”.

The Company has made significant investments to facilitate the use of renewable and lower-carbon

energy including wind generation, the Maritime Link in Atlantic Canada, and in Florida, solar generation

and modernization of the Big Bend Power Station. Tampa Electric has taken significant steps to reduce

overall emissions at its facilities as a result of its capital investment plan which has and will continue to

reduce carbon dioxide emissions.

In 2022, NSPI achieved reductions of carbon dioxide emissions of

approximately 45 per cent from 2005 levels. NSPI expects to exceed the Canadian target of 40-45 per

cent reduction by 2030, as set out in the Canadian Net-Zero Emissions Accountability Act. Both the

Government of Nova Scotia and the Government of Canada have enacted or introduced legislation that

includes goals of net-zero GHG emissions by 2050. The Province of Nova Scotia has established targets

with respect to the percentage of renewable energy in NSPI’s generation mix, reductions in GHG

emissions, as well as the goal to phase out coal-fired electricity generation by 2030. Failure to meet such

goals by 2030 could result in material fines, penalties, other sanctions and adverse reputational impacts.

NSPI continues to work with both the provincial and federal governments on measures to seek to address

their carbon reduction goals. Future compliance with provincial and federal GHG emission caps, coal

phase out requirements and targets, and renewable standards has been challenged as a result of the

constraints imposed by the enactment of Bill 212, “Public Utilities Act (amended)”. Within Emera’s natural

gas utilities, there are ongoing efforts to reduce methane and carbon dioxide emissions through

replacement of aging infrastructure, more efficient operations, operational and supply chain optimization,

and support of public policy initiatives that address the effects of climate change.

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

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

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

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

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

and initiatives.

Physical Impacts

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

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

warming air temperatures and increasing drought conditions. Substantially all of the Company’s fossil

fueled generation assets are located at or near coastal sites and, as such, are exposed to the separate

and combined effects of rising sea levels and increasing storm intensity, including storm surges and

flooding. Refer to “Weather Risk” for further information.

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

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

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

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

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

restoration costs over time.

Reputation

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

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

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

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

Markets

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

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

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

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

developments and adaptive changes to supply chain procurement strategies.

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

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

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

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

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

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

or zero carbon dioxide emissions.

Policy

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

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

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

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

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

medium and longer terms, this could potentially lead to a significant portion of hydrocarbon infrastructure

assets being subject to additional regulation and limitations in respect of GHG emissions and operations.

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

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

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

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

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

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

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

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

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

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

Regulatory

Depending on the regulatory response to government legislation and regulations, the Company may be

exposed to the risk of reduced recovery through rates in respect of the affected assets. Valuation

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

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

while being responsive to customers’ and stakeholders’ objectives.

Legal

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

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

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

change risks.

Water Resources

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

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

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

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

as in other markets.

The Company operates hydroelectric generation in certain of its markets. Such generation depends on

availability of water and the hydrological profile of water sources. Changes in precipitation patterns, water

temperatures and air temperatures could adversely affect the availability of water and consequently the

amount of electricity that may be produced from such facilities. The Company is reinvesting in the

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

monitor changing hydrology patterns. Such issues may also affect the availability of third-party owned

hydroelectricity purchased power sources.

Weather Risk

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

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

and extreme weather conditions associated with climate change. Refer to “Global Climate Change Risk”.

Fluctuations in the amount of electricity or natural gas used by customers can vary significantly in

response to seasonal changes in weather and could impact the operations, results of operations, financial

condition, and cash flows of the Company’s utilities. For example, Tampa Electric could see lower

demand in summer months if temperatures are cooler than expected. Further, extreme weather

conditions such as hurricanes and other severe weather conditions which may be associated with climate

change could cause these seasonal fluctuations to be more pronounced. In the absence of a regulatory

recovery mechanism for unanticipated costs, such events could influence the Company’s results of

operations, financial conditions or cash flows.

Extreme weather events create a risk of physical damage to the Company’s assets. High winds can

impact structures and cause widespread damage to transmission and distribution infrastructure, solar

generation, and wind powered generation. Increased frequency and severity of weather events increases

the likelihood that the duration of power outages and fuel supply disruptions could increase. Increased

frequency and intensity of flooding and storm surge could adversely affect the operations of utilities and in

particular generation assets. The impact of extreme weather events would be amplified if the same

events affect multiple utilities.

Each of Emera’s regulated electric utilities have programs for storm hardening of transmission and

distribution facilities to minimize damage, but there can be no assurance that these measures will fully

mitigate the risk. This risk to transmission and distribution facilities is typically not insured, and as such

the restoration cost is generally recovered through regulatory processes, either in advance through

reserves or designated self-insurance funds, or after the fact through the establishment of regulatory

assets. Recovery is not assured and is subject to prudency review. The risk to generation assets is, in

part, mitigated through the design, siting, construction and maintenance of such facilities, regular risk

assessments, engineered mitigation, emergency storm response plans, and insurance.

The risk of wildfires is addressed primarily through asset management programs for natural gas

transmission and distribution operations, and vegetation management programs for electric transmission

and distribution facilities. If it is found to be responsible for such a fire, the Company could suffer costs,

losses and damages, all or some of which may not be recoverable through insurance, legal, regulatory

cost recovery or other processes. If not recovered through these means, they could materially affect

Emera’s business and financial results including its reputation with customers, regulators, governments

and financial markets. Resulting costs could include fire suppression costs, regeneration, timber value,

increased insurance costs and costs arising from damages and losses incurred by third parties.

Changes in Environmental Legislation

Emera is subject to regulation by federal, provincial, state, regional and local authorities regarding

environmental matters, primarily related to its utility operations. This includes laws setting GHG emissions

standards and air emissions standards. Emera is also subject to laws regarding waste management,

wastewater discharges and aquatic and terrestrial habitats.

Changes to GHG emissions standards and air emissions standards could adversely affect Emera’s

operations and financial performance. Legislative or regulatory changes could influence decisions

regarding early retirement of generation facilities and may result in stranded costs if the Company is not

able to fully recover the costs and investment in the affected generation assets. Recovery is not assured

and is subject to prudency review. Legislative or regulatory changes may curtail sales of natural gas to

new customers, which could reduce future customer growth in Emera’s natural gas businesses. Stricter

environmental laws and enforcement of such laws in the future could increase Emera’s exposure to

additional liabilities and costs. These changes could also affect earnings and strategy by changing the

nature and timing of capital investments.

In addition to imposing continuing compliance obligations, there are permit requirements, laws and

regulations authorizing the imposition of penalties for non-compliance, including fines, injunctive relief,

and other sanctions. The cost of complying with current and future environmental requirements is, and

may be, material to Emera. Failure to comply with environmental requirements or to recover

environmental costs in a timely manner through rates, could have a material adverse effect on Emera. In

addition, Emera’s business could be materially affected by changes in government policy, utility

regulation, and environmental and other legislation that could occur in response to environmental and

climate change concerns.

Emera manages its environmental risk by operating in a manner that is respectful and protective of the

environment and in compliance with applicable legal requirements and Company policy. Emera has

implemented this policy through the development and application of environmental management systems

in its operating subsidiaries. Comprehensive audit programs are in place to regularly test compliance.

Cybersecurity Risk

Emera is exposed to potential risks related to cyberattacks and unauthorized access. The Company

increasingly relies on IT systems network, and cloud infrastructure to manage its business and safely

operate its assets, including controls for interconnected systems of generation, distribution and

transmission as well as financial, billing and other business systems. Emera also relies on third-party

service providers to conduct business. As the Company operates critical infrastructure, it may be at

greater risk of cyberattacks by third parties, which could include nation-state-controlled parties. This risk

may be further elevated by geo-political risks such as the ongoing conflict between Russia and Ukraine.

Cyberattacks can reach the Company’s assets and information via their interfaces with third parties or the

public internet and gain access to critical infrastructures. Cyberattacks can also occur via personnel with

direct access to critical assets or trusted networks. Methods used to attack critical assets could include

general purpose or energy-sector-specific malware delivered via network transfer, removable media,

viruses, attachments, or links in e-mails. The methods used by attackers are continuously evolving and

can be difficult to predict and detect.

Despite security measures in place, that are described below, the Company’s systems, assets and

information could experience security breaches that could cause system failures, disrupt operations, or

adversely affect safety. Such breaches could compromise customer, employee-related or other

information systems and could result in loss of service to customers, unavailability of critical assets, safety

issues, or the release, destruction, or misuse of critical, sensitive or confidential information. These

breaches could also delay delivery or result in contamination or degradation of hydrocarbon products the

Company transports, stores or distributes.

Cyberattacks or unauthorized accesses may cause costs, losses and damages all, or some of which, may

not be recoverable (through insurance, legal, regulatory cost recovery or other processes). This could

materially adversely affect Emera’s business and financial results including its reputation with customers,

regulators, governments and financial markets. Resulting costs could include, amongst others, response,

recovery and remediation costs, increased protection or insurance costs and costs arising from damages

and losses incurred by third parties. If any such security breaches occur, there is no assurance they can

be adequately addressed in a timely manner.

The Company seeks to manage these risks by aligning to a common set of cybersecurity standards and

policies derived, in part, on the National Institute of Standards and Technology’s Cyber Security

Framework, periodic security testing, program maturity objectives, cybersecurity incident readiness

program, and employee communication and training. With respect to certain of its assets, the Company is

required to comply with rules and standards relating to cybersecurity and IT including, but not limited to,

those mandated by bodies such as the North American Electric Reliability Corporation,

Northeast Power

Coordinating Council, and the United States Department of Homeland Security. The status of key

elements of the Company’s cybersecurity program is reported to the RSC.

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 expenditures, results of financing efforts, or credit risk and counterparty risk; which

could result in a material adverse effect on the Company’s business. The Company maintains pandemic

and business contingency plans in each of its operations to manage and help mitigate the impact of any

such public health threat.

Energy Consumption Risk

Emera’s rate-regulated utilities are affected by demand for energy based on changing customer patterns

due to fluctuations in a number of factors including general economic conditions, weather events,

customers’ focus on energy efficiency, changes in rates, and advancements in new technologies such as

rooftop solar, electric vehicles and battery storage. Government policies promoting distributed generation,

and new technology developments that enable those policies, have the potential to impact how electricity

enters the system and how it is bought and sold. In addition, increases in distributed generation may

impact demand resulting in lower load and revenues. These changes could negatively impact Emera’s

operations, rate base, net earnings, and cash flows. The Company’s rate-regulated utilities are focused

on understanding customer demand, energy efficiency, and government policy to ensure that the impact

of these activities benefit customers, that they do not negatively impact the reliability of the energy service

and that they are addressed through regulations.

Foreign Exchange Risk

The Company is exposed to foreign currency exchange rate changes. Emera operates internationally,

with an increasing amount of the Company’s net income earned outside of Canada. As such, Emera is

exposed to movements in exchange rates between the CAD and, particularly, the USD, which could

positively or adversely affect results.

Consistent with the Company’s risk management policies, Emera manages currency risks through

matching United States denominated debt to finance its Unites States operations and may use foreign

currency derivative instruments to hedge specific transactions and earnings exposure. The Company may

enter FX forward and swap contracts to limit exposure on certain foreign currency transactions such as

fuel purchases, revenue streams and capital expenditures, and on net income earned outside of Canada.

The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently

incurred costs, including FX.

The Company does not utilize derivative financial instruments for foreign currency trading or speculative

purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on

net investments in foreign subsidiaries do not impact net income as they are reported in Accumulated

Other Comprehensive Income (Loss) ("AOCI”) (“AOCL”).

Liquidity and Capital Market Risk

Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial

obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to

determine whether sufficient funds are available. Liquidity and capital needs could be financed through

internally generated cash flows, asset sales, short-term credit facilities, and ongoing access to capital

markets. The Company reasonably expects liquidity sources to 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 PP&E and the risk associated with changes in interest rates could have an adverse effect

on the cost of financing. The Company’s future access to capital and cost of borrowing may be impacted

by various market disruptions. The inability to access cost-effective capital could have a material impact

on Emera’s ability to fund its growth plan.

Emera is subject to financial risk associated with changes in its credit ratings. There are a number of

factors that rating agencies evaluate to determine credit ratings, including the Company’s business, its

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

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

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

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

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

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

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

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

manages these risks by actively monitoring and managing key financial metrics with the objective of

sustaining investment grade credit ratings.

The Company has exposure to its own common share price through the issuance of various forms of

stock-based compensation, which affect earnings through revaluation of the outstanding units every

period. The Company uses equity derivatives to reduce the earnings volatility derived from stock-based

compensation.

General Economic Risk

The Company has exposure to the macro-economic conditions in North America and in other geographic

regions in which Emera operates. Like most utilities, economic factors such as consumer income,

employment and housing affect demand for electricity and natural gas and, in turn, the Company’s

financial results. Adverse changes in general economic conditions and inflation may impact the ability of

customers to afford rate increases arising from increases to fuel, operating, capital, environmental

compliance, and other costs, and therefore could materially affect Emera and its utilities. This may also

result in higher credit and counterparty risk, adverse shifts in government policy and legislation, and/or

increased risk to full and timely recovery of costs and regulatory assets.

Interest Rate Risk

Emera utilizes a combination of fixed and floating rate debt financing for operations and capital

expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk

through a portfolio approach that includes the use of fixed and floating rate debt with staggered

maturities. The Company will, from time to time, issue long-term debt or enter interest rate hedging

contracts to limit its exposure to fluctuations in floating interest rate debt.

For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt

costs are recovered from customers. Regulatory ROE will generally follow the direction of interest rates,

such that regulatory ROEs are likely to fall in times of reducing interest rates and rise in times of

increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory

process. Rising interest rates may also negatively affect the economic viability of project development

and acquisition initiatives.

As with most other utilities and other similar yield-returning investments, Emera’s share price may be

affected by changes in interest rates and could underperform the market in an environment of rising

interest rates.

Inflation Risk

The Company may be exposed to changes in inflation that may result in increased operating and

maintenance costs, capital investment, and fuel costs compared to the revenues provided by customer

rates. Emera’s utilities have budgeting and forecasting processes to identify inflationary risk factors and

measure operating performance, as well as collective bargaining agreements that mitigate the short-term

impact of inflation on labour costs.

Project Development and Land Use Rights Risk

The Company’s capital plan includes significant investment in generation, infrastructure modernization,

and customer-focused technologies. Any projects planned or currently in construction, particularly

significant capital projects, may be subject to risks including, but not limited to, impact on costs from

schedule delays, risk of cost overruns, ensuring compliance with operating and environmental

requirements and other events within or beyond the Company’s control. The Company’s projects may

also require approvals and permits at the federal, provincial, state, regional and local levels. There is no

assurance that Emera will be able to obtain the necessary project approvals or applicable permits or

receive regulatory approval to recover the costs in rates.

Some of the Company’s assets are located on land owned by third parties, including Indigenous Peoples,

and may be subject to land claims. Present or future assets may be located on lands that have been used

for traditional purposes and therefore subject to specific consultations, consents, or conditions for

development or operation. If the Company’s rights to locate and operate its assets on any such lands are

subject to expiry or become invalid, it may incur material costs to renew rights or obtain such rights. If

reasonable terms for land-use rights cannot be negotiated, the Company may incur significant costs to

remove and relocate its assets and restore the land. Additional costs incurred could cause projects to be

uneconomical to proceed with.

Emera manages these project development and land use rights risks by deploying robust project and risk

management approaches, led by teams with extensive experience in large projects. The Company

consults with Indigenous Peoples in obtaining approvals, constructing, maintaining and operating such

facilities, consistent with laws and public policy frameworks. Emera maintains relationships through on-

going communications with stakeholders, including Indigenous Peoples, landowners and governments.

Counterparty Risk

Emera is exposed to risk related to its reliance on certain key partners, suppliers, and customers, any of

which may endure financial challenges resulting from commodity price and market volatility, economic

instability or adversity, adverse political or regulatory changes and other causes which may cause or

contribute to such parties’ insolvency, bankruptcy,

restructuring or default on their contractual obligations

to Emera.

Emera is also exposed to potential losses related to amounts receivable from customers,

energy marketing collateral deposits and derivative assets due to a counterparty’s non-performance

under an agreement.

Emera manages this counterparty risk through due diligence and third-party risk assessment processes

prior to signing contracts, contractual rights and remedies, regulatory frameworks, and by monitoring

significant developments with its customers, partners and suppliers. The Company also manages credit

risk with policies and procedures for counterparty analysis, exposure measurement, and exposure

monitoring and mitigation. Credit assessments may be conducted on new customers and counterparties,

and deposits or collateral may be requested on certain accounts. There is no assurance that

management strategies will be effective,

and significant counterparty defaults could have a material effect

on the Company.

Country Risk

The majority of Emera’s earnings are from outside of Canada, mostly concentrated in the United States.

Emera’s investments are currently in regions where political and economic risks are considered by the

Company to be acceptable. For more information, refer to the “Regulatory and Political Risk” and

“General Economic Risk” sections above. Emera’s operations in some countries may be subject to

changes in economic growth, restrictions on the repatriation of income or capital exchange controls,

inflation, the effect of global health, safety and environmental matters, including climate change, or

economic conditions and market conditions, and change in financial policy and availability of credit. The

Company mitigates this risk through a rigorous approval process for investment, and by forecasting cash

requirements on a continuous basis to determine whether sufficient funds are available in all affiliates.

Commodity Price Risk

The Company’s utility fuel supply is subject to commodity price risk. In addition, Emera Energy is subject

to commodity price risk through its portfolio of commodity contracts and arrangements.

The Company manages this risk through established processes and practices to identify, monitor, report

and mitigate these risks. These include the Company’s commercial arrangements, such as the

combination of supply and purchase agreements, asset management agreements, pipeline transportation

agreements, and financial hedging instruments. In addition, its credit policies, counterparty credit

assessments, market and credit position reporting, and other risk management and reporting practices,

are also used to manage and mitigate this risk.

Regulated Utilities

The Company’s utility fuel supply is exposed to broader global conditions, which may include impacts on

delivery reliability and price, despite contracted terms. Supply and demand dynamics in fuel markets can

be affected by a wide range of factors which are difficult to predict and may change rapidly, including but

not limited to, currency fluctuations, changes in global economic conditions, natural disasters,

transportation or production disruptions, and geo-political risks, such as political instability, conflicts,

changes to international trade agreements, trade sanctions or embargos. The Company seeks to manage

this risk using financial hedging instruments and physical contracts and through contractual protection

with counterparties, where applicable.

The majority of Emera’s regulated electric and gas utilities have adopted and implemented fuel

adjustment mechanisms and purchased gas adjustment mechanisms respectively, which further helps

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

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

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

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

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

Emera Energy Marketing and Trading

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

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

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

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

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

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

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

increased costs to the business.

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

including an estimated VaR analysis of its exposures. The VaR

amount represents an estimate of the

potential change in fair value that could occur from changes in Emera Energy’s portfolio or changes in

market factors within a given confidence level, if an instrument or portfolio is held for a specified time

period. The VaR calculation is used to quantify exposure to market risk associated with physical

commodities, primarily natural gas and power positions.

Future Employee Benefit Plan Performance and Funding Risk

Emera subsidiaries have both defined benefit and defined contribution employee pension plans that cover

their employees and retirees. All defined benefit plans are closed to new entrants, except for the TECO

Energy Group Retirement Plan. The cost of providing these benefit plans varies depending on plan

provisions, interest rates, inflation, investment performance and actuarial assumptions concerning the

future. Actuarial assumptions include earnings on plan assets, discount rates (interest rates used to

determine funding levels, contributions to the plans and the pension and post-retirement liabilities) and

expectations around future salary growth, inflation and mortality. Three of the largest drivers of cost are

investment performance, interest rates and inflation, which are affected by global financial and capital

markets. Depending on future interest rates and future inflation and actual versus expected investment

performance, Emera could be required to make larger contributions in the future to fund these plans,

which could adversely affect Emera’s cash flows, financial condition and operations.

Each of Emera’s employee defined benefit pension plans are managed according to an approved

investment policy and governance framework. Emera employs a long-term approach with respect to asset

allocation and each investment policy outlines the level of risk which the Company is prepared to accept

with respect to the investment of the pension funds in achieving both the Company’s fiduciary and

financial objectives. Studies are routinely undertaken approximately every five years with the objective

that the plans’ asset allocations are appropriate for meeting Emera’s long-term pension objectives.

Labour Risk

Emera’s ability to deliver service to its customers and to execute its growth plan depends on attracting,

developing and retaining a skilled workforce. Utilities are faced with demographic challenges related to

trades, technical staff and engineers with an increasing number of employees expected to retire over the

next several years. Failure to attract, develop and retain an appropriately qualified workforce could

adversely affect the Company’s operations and financial results. Emera seeks to manage this risk through

maintaining competitive compensation programs, a dedicated talent acquisition team, human resources

programs and practices, including ethics and diversity training, employee engagement surveys,

succession planning for key positions and apprenticeship programs.

Approximately 32 per cent of Emera’s labour force is represented by unions and subject to collective

labour agreements. The inability to maintain or negotiate future agreements on acceptable terms could

result in higher labour costs and work disruptions, which could adversely affect service to customers and

have an adverse effect on the Company’s earnings, cash flow and financial position. Emera seeks to

manage this risk through ongoing discussions and working to maintain positive relationships with local

unions. The Company maintains contingency plans in each of its operations to manage and reduce the

effect of any potential labour disruption.

IT Risk

Emera relies on various IT systems to manage operations. This subjects Emera to inherent costs and

risks associated with maintaining, upgrading, replacing and changing these systems. This includes

impairment of its IT, potential disruption of internal control systems, substantial capital expenditures,

demands on management time and other risks of delays, difficulties in upgrading existing systems,

transitioning to new systems or integrating new systems into its current systems. Emera’s digital

transformation strategy, including investment in infrastructure modernization and customer focused

technologies, is driving increased investment in IT solutions, resulting in increased project risks

associated with the implementation of these solutions.

Emera manages these risks through IT asset lifecycle planning and management, governance, internal

auditing and testing of systems, and executive oversight. Employees with extensive subject matter

expertise assist in risk identification and mitigation, project management, implementation, change

management and training. System resiliency, formal disaster recovery and backup processes, combined

with critical incident response practices, table-top exercises, and simulations, help mitigate operational

disruptions.

Income Tax Risk

The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in

Canada, the United States and the Caribbean. Any such changes could affect the Company’s future

earnings, cash flows, and financial position. The value of Emera’s existing deferred 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.

System Operating and Maintenance Risks

The safe and reliable operation of electric generation and electric and natural gas transmission and

distribution systems is critical to Emera’s operations. There are a variety of hazards and operational risks

inherent in operating electric utilities and natural gas transmission and distribution pipelines. Electric

generation, transmission and distribution operations can be impacted by risks such as mechanical

failures, supply chain issues impacting timely access to critical equipment, activities of third parties,

terrorism, cyberattacks, damage to facilities, solar panels and infrastructure caused by hurricanes,

storms, falling trees, lightning strikes, floods, fires and other natural disasters. Natural gas pipeline

operations can also be impacted by risks such as leaks, explosions, mechanical failures, activities of third

parties, terrorism, cyberattacks, and damage to the pipeline facilities and equipment caused by

hurricanes, storms, floods, fires and other natural disasters. Refer to “Global Climate Change Risk” and

“Weather Risk”. Electric utility and natural gas transmission and distribution pipeline operation interruption

could negatively affect revenue, earnings, and cash flows as well as customer and public confidence, and

public safety.

Emera manages these risks by investing in a highly skilled workforce, operating prudently, preventative

maintenance, safety and operations management systems, third-party risk program, and making effective

capital investments. Insurance, warranties, or recovery through regulatory mechanisms may not cover

any or all these losses, which could adversely affect the Company’s results of operations and cash flows.

Fuel Supply Disruptions

Emera’s electric and natural gas utilities are also exposed to the risk of fuel supply chain disruptions, both

within and outside their service territories, which may be caused by severe weather or natural disasters.

This may also be caused by damage to, operational issues with, terrorist or cyberattacks on, third party

fuel production, storage, pipeline, and distribution facilities. The risk of fuel supply disruptions is managed

through contractual protections, maintaining a diversity of fuel suppliers and transportation contracts, and

contracting for access to third-party storage facilities. Significant unanticipated fuel supply disruptions,

such as those which arose from Winter Storm Uri in February 2021, could result in increased exposure to

commodity price risk for Emera’s regulated electric and gas utilities and Emera Energy, and these could

have adverse effects on service to utility customers and on the Company’s reputation, earnings, cash flow

and financial position.

Uninsured Risk

Emera and its subsidiaries maintain insurance to cover accidental loss suffered to its facilities and to

provide indemnity in the event of liability to third parties. This is consistent with Emera’s risk management

policies. Certain facilities, in particular coal and other thermal generation, may, over time, become more

difficult (or uneconomic) to insure as a result of the impact of global climate change. Refer to “Global

Climate Change Risk – Markets”. There are certain elements of Emera’s operations which are not

insured. These include a significant portion of its electric utilities’ transmission and distribution assets, as

is customary in the industry. The cost of this coverage is not economically viable. In addition, Emera

accepts deductibles and self-insured retentions under its various insurance policies. Insurance is subject

to coverage limits as well as time sensitive claims discovery and reporting provisions and there can be no

assurance that the types of liabilities or losses that may be incurred by the Company and its subsidiaries

will be covered by insurance.

The occurrence of significant uninsured claims, claims in excess of the insurance coverage limits

maintained by Emera and its subsidiaries, or claims that fall within a significant self-insured retention

could have a material adverse effect on Emera’s results of operations, cash flows and financial position, if

regulatory recovery is not available.

The Company mitigates its uninsured risk by ensuring insurance limits align with risk exposures, and for

uninsured assets and operations, that appropriate risk assessments and mitigation measures are in

place. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of

prudently incurred costs, including uninsured losses.

RISK MANAGEMENT INCLUDING FINANCIAL

INSTRUMENTS

Emera’s risk management policies and procedures provide a framework through which management

monitors various risk exposures. The risk management policies and practices are overseen by the Board

of Directors. The Company has established a number of processes and practices to identify, monitor,

report on and mitigate material risks to the Company. This includes establishment of the ERMC, whose

responsibilities include preparing an updated risk dashboard and heat map presented at regular meetings

of the Board’s Risk and Sustainability Committee. Furthermore, a corporate team independent from

operations is responsible for tracking and reporting on market and credit risks.

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

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

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

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

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

contracts are classified as held-for-trading (“HFT”). Collectively, these contracts and financial instruments

are considered derivatives.

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

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

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

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

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

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

commodity, and the Company deems the counterparty creditworthy.

The Company continually assesses

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

under this exemption where the criteria are no longer met.

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

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

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

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

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

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

accounting.

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

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

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

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

losses resulting from settlement of these derivatives related to fuel for generation and purchased power

will be refunded to or collected from customers in future rates. Tampa Electric has no derivatives related

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

which ended 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.

Derivative Assets and Liabilities Recognized on the Balance Sheet

As at

December 31

millions of dollars

2022

2021

Regulatory Deferral:

Derivative instrument assets

(1)

238

237

Derivative instrument liabilities

(2)

(25)

(20)

Regulatory assets

(1)

Regulatory liabilities

(2)

(230)

(241)

Net asset (liability)

(1)

HFT Derivatives:

Derivative instrument assets

(1)

153

Derivatives instruments liabilities

(2)

(1,025)

(662)

Net liability

(872)

(609)

Other Derivatives:

Derivative instrument assets

(1)

Derivatives instruments liabilities

(2)

(28)

Net asset (liability)

(23)

(1) Current and other assets.

(2) Current and long-term liabilities.

Realized and Unrealized Gains (Losses) Recognized in Net Income

For the

Year ended December 31

millions of dollars

2022

2021

Regulatory Deferral:

Regulated fuel for generation and purchased power

(1)

210

HFT Derivatives:

Non-regulated operating revenues

(138)

Other Derivatives:

OM&G

(22)

Other income, net

(24)

Net gains (losses)

(46)

Total net gains (losses)

228

(75)

(1)

Realized gains (losses) on derivative instruments settled and consumed in the period, hedging relationships

that have been

terminated or the hedged transaction is no longer probable. Realized gains (losses) recorded in inventory will be recognized

“Regulated fuel for generation and purchased power” when the hedged item is consumed.

As of December 31, 2022, the unrealized gain in AOCI was $16 million, net of tax (2021 – $18 million, net

of tax). For the year ended December 31, 2022, unrealized gains of $2 million (2021 – $1 million), have

been reclassified into interest expense.

DISCLOSURE AND INTERNAL CONTROLS

Management is responsible for establishing and maintaining adequate disclosure controls and

procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National

Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”). The

Company’s internal control framework is based on the criteria published in the Internal Control -

Integrated Framework (2013), a report issued by the Committee of Sponsoring Organizations (“COSO”) of

the Treadway Commission. Management, including the Chief Executive Officer and Chief Financial

Officer, evaluated the design and effectiveness of the Company’s DC&P and ICFR as at December 31,

2022 to provide reasonable assurance regarding the reliability of financial reporting in accordance with

USGAAP.

Management recognizes the inherent limitations in internal control systems, no matter how well designed.

Control systems determined to be appropriately designed can only provide reasonable assurance with

respect to the reliability of financial reporting and may not prevent or detect all misstatements.

There were no changes in the Company’s ICFR, during the year ended December 31, 2022, that have

materially affected, or are reasonably likely to materially affect, the Company’s internal control over

financial reporting.

CRITICAL ACCOUNTING ESTIMATES

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

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

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

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

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

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

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

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

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

any adjustments recognized in income in the year they arise.

Rate Regulation

The rate-regulated accounting policies of Emera’s rate-regulated subsidiaries and regulated equity

investments are subject to examination and approval by their respective regulators and may differ from

the accounting policies of non-rate-regulated companies. Differences occur when regulators render their

decisions on rate applications or other matters, and generally involve a difference in the timing of revenue

and expense recognition. The accounting for these items is based on expectations of the future actions of

the regulators. Assumptions and judgments used by regulatory authorities continue to have an impact on

the recovery of costs, the rate earned on invested capital, and the timing and amount of assets to be

recovered. The application of regulatory accounting guidance is a critical accounting policy as a change in

these assumptions may result in a material impact on reported assets, liabilities and the results of

operations.

As at December 31, 2022, the Company has recorded $3,620 million (2021 – $2,566 million) of regulatory

assets and $2,273 million (2021 – $2,055 million) of regulatory liabilities.

Accumulated Reserve – Cost of Removal

Tampa

Electric, PGS, NMGC and NSPI recognize non-ARO costs of removal (“COR”) as regulatory

liabilities. The non-ARO COR represent estimated funds received from customers through depreciation

rates to cover future COR of PP&E upon retirement that are not legally required. The companies accrue

for COR over the life of the related assets based on depreciation studies approved by their respective

regulators. The costs are estimated based on historical experience and future expectations, including

expected timing and estimated future cash outlays. As at December 31, 2022, the balance of the

Accumulated reserve – COR within regulatory liabilities was $895 million (2021 – $819 million).

Pension and Other Post-Retirement Employee Benefits

The Company provides post-retirement benefits to employees, including defined benefit pension plans.

The cost of providing these benefits is dependent upon many factors that result from actual plan

experience and assumptions of future expectations.

The accounting related to employee post-retirement benefits is a critical accounting estimate. Changes in

the estimated benefit obligation, affected by employee demographics, including age, compensation

levels, employment periods, contribution levels and earnings, could have a material impact on reported

assets, liabilities, accumulated other comprehensive income and results of operations. Changes in key

actuarial assumptions, including anticipated rates of return on plan assets and discount rates used in

determining the accrued benefit obligation and benefit costs, could change annual funding requirements.

This could have a significant impact on the Company’s annual earnings and cash requirements.

The pension plan assets are comprised primarily of equity and fixed income investments. Fluctuations in

actual equity market returns and changes in interest rates may result in changes to pension costs in

future periods.

The Company’s accounting policy is to amortize the net actuarial gain or loss that exceeds 10 per cent of

the greater of the projected benefit obligation / accumulated post-retirement benefit obligation (“PBO”)

and the market-related value of assets, over active plan members’ average remaining service period. For

the largest plans this is currently 8.3 years (8.7 years for 2022 benefit cost) for the Canadian plans and a

weighted average of 11.4 years for the United States plans). The Company’s use of smoothed asset

values reduces volatility related to the amortization of actuarial investment experience. As a result, the

main cause of volatility in reported pension cost is the discount rate used to determine the PBO.

The discount rate used to determine benefit costs is based on the yield of high quality long-term corporate

bonds in each operating entity’s country and is determined with reference to bonds which have the same

duration as the PBO as at January 1 of the fiscal year. The following table shows the discount rate for

benefit cost purposes and the expected return on plan assets for each plan:

2022

2021

Discount rate for

benefit cost

purposes

Expected

return on

plan assets

Discount rate for

benefit cost purposes

Expected

return on

plan assets

TECO Energy Group Retirement

Plan

2.78%

6.50%

2.38%

6.70%

TECO Energy Group Supplemental

Executive Retirement Plan

(1)

2.35/5.33%

N/A

1.84%

N/A

TECO Energy Group Benefit

Restoration Plan (1)

2.27/4.19/5.48%

N/A

1.71%

N/A

TECO Energy Post-retirement

Health and Welfare Plan

2.84%

N/A

2.47%

N/A

New Mexico Gas Company Retiree

Medical Plan

2.85%

1.50%

2.49%

4.00%

NSPI

3.25%, 3.48%

5.75%

2.59%, 2.85%

5.25%

GBPC Salaried

5.75%

6.00%

4.25%

6.00%

GBPC Union

5.75%

5.35%

5.65%

(1) The discount rate and expected return on assets for benefit cost purposes is updated throughout the year as special events

occur, such as settlements and curtailments.

Based on management’s estimate, the reported benefit cost for defined benefit and defined contribution

plans was $64 million in 2022 (2021 – $85 million). The reported benefit cost is impacted by numerous

assumptions, including the discount rate and asset return assumptions. A 0.25 per cent change in the

discount rate and asset return assumptions would have had +/- impact on the 2022 benefit cost of $0.5

million and $1 million respectively (2021 – $1 million and $3 million).

Unbilled Revenue

Electric and gas revenues are billed on a systematic basis over a one or two-month period for NSPI and a

one-month period for other Emera utilities. At the end of each month, the Company must make an

estimate of energy delivered to customers since the date their meter was last read and determine related

revenues earned but not yet billed. The unbilled revenue is estimated based on several factors, including

current month’s generation, estimated customer usage by class, weather, line losses, inter-period

changes to customer classes and applicable customer rates. Based on the extent of estimates included in

the determination of unbilled revenue, actual results may differ from the estimate. At December 31, 2022,

unbilled revenues totalled $424 million (2021 – $318 million) on total regulated operating revenues of

$7,154 million (2021 – $5,926 million).

Property, Plant and Equipment

PP&E represents 58 per cent of total assets on the Company’s balance sheet and include the generation,

transmission and distribution, and other assets of the Company.

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

the depreciable assets in each category. The service lives of regulated PP&E are determined based on

depreciation studies and require appropriate regulatory approval. Due to the magnitude of the Company’s

PP&E, changes in estimated depreciation rates can have a material impact on depreciation expense and

accumulated depreciation.

Depreciation expense was $927 million for the year ended December 31, 2022 (2021 – $877 million).

Goodwill Impairment Assessments

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. Application of the goodwill impairment test requires

management judgment on significant assumptions and estimates. When assessing goodwill for

impairment, the Company has the option of first performing a qualitative assessment to determine

whether a quantitative assessment is necessary. In performing a qualitative assessment management

considers, among other factors, macroeconomic conditions, industry and market considerations and

overall financial performance.

If the Company performs 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. Significant assumptions used in estimating the fair

value include discount and growth rates, rate case assumptions including future cost of capital, valuation

of the reporting units' net operating loss (“NOL”) and projected operating and capital cash flows. Adverse

changes in these assumptions could result in a future material impairment of the goodwill assigned to

Emera’s reporting units.

As of December 31, 2022, $6,009 million of Emera’s goodwill represents the excess of the acquisition

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

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

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

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

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

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

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

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

NMGC reporting unit exceeded its carrying amount, including goodwill. As a result of this assessment, no

impairment charges were recognized.

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

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

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

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

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

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

economic environment, including the risk-free rate assumption. As a result of this assessment, a goodwill

impairment charge of $73 million was recorded in 2022, reducing the GBPC goodwill balance to nil as at

December 31, 2022. No impairment was recorded in 2021. For further detail, refer to note 22.

As of December 31, 2022, the Company had goodwill with a total carrying amount of $6,012 million

(December 31, 2021 – $5,696 million). The change in the carrying value of goodwill from 2021 to 2022

was a result of the effect of the FX translation of Emera’s foreign affiliates, partially offset by the GBPC

impairment.

Long-Lived Assets Impairment Assessments

In accordance with accounting guidance for long-lived assets, the Company assesses whether there has

been an impairment of long-lived assets and intangibles when a triggering event occurs, such as a

significant market disruption or the sale of a business. The assessment involves comparing 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 believes accounting estimates related to asset impairments are critical estimates, as they

are highly susceptible to change and the impact of an impairment on reported assets and earnings could

be material. Management is required to make assumptions based on expectations regarding the results

of operations for significant/indefinite future periods and the current and expected market conditions in

such periods. Markets can experience significant uncertainties. Estimates based on the Company’s

assumptions relating to future results of operations or other recoverable amounts are based on a

combination of historical experience, fundamental economic analysis, observable market activity and

independent market studies. The Company’s expectations regarding uses and holding periods of assets

are based on internal long-term budgets and projections, which consider external factors and market

forces, as of the end of each reporting period. Assumptions made by management are consistent with

generally accepted industry approaches and assumptions used for valuation and pricing activities.

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

impairment charges were recognized in either 2022 or 2021.

Income Taxes

Income taxes are determined based on the expected tax treatment of transactions recorded in the

consolidated financial statements. In determining income taxes, tax legislation is interpreted in a variety of

jurisdictions, the likelihood that deferred tax assets will be realized is assessed and assumptions about

the expected timing of the reversal of deferred tax assets and liabilities are made. Uncertainty associated

with application of tax statutes and regulations and the outcomes of tax audits and appeals, requires that

judgments and estimates be made in the accrual process and in the calculation of effective tax rates.

Only income tax benefits that meet the “more likely than not” threshold may be recognized or continue to

be recognized. Unrecognized tax benefits are evaluated quarterly and changes are recorded based on

new information, including issuance of relevant guidance by the courts or tax authorities and

developments in examinations of the Company’s tax returns.

The Company believes the accounting estimates related to income taxes are critical estimates. The

realization of deferred tax assets is dependent upon the generation of sufficient taxable income, both

operating and capital, in future periods. A change in the estimated valuation allowance could have a

material impact on reported assets and results of operations. Administrative actions of the tax authorities,

changes in tax law or regulation, and the uncertainty associated with the application of tax statutes and

regulations, could change the Company’s estimate of income taxes, including the potential for elimination

or reduction of the Company’s ability to realize tax benefits and to utilize deferred tax assets.

Asset Retirement Obligations

Measurement of the fair value of AROs requires the Company to make reasonable estimates concerning

the method and timing of settlement associated with the legally obligated costs. There are uncertainties in

estimating future asset-retirement costs due to potential events, such as changing legislation or

regulations, and advances in remediation technologies. Emera has AROs associated with the remediation

of generation, transmission, distribution and pipeline assets.

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. Accretion expense is included

as part of “Depreciation and amortization expense”. Any accretion expense not yet approved by the

regulator is recorded in “PP&E” and included in the next depreciation study. Accordingly,

changes to the

ARO or cost recognition attributable to changes in the factors discussed above, should not impact the

results of operations of the Company.

Some of the Company’s transmission and distribution assets may have conditional AROs 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 when an amount can be determined.

As at December 31, 2022, AROs recorded on the balance sheet were $174 million (2021 – $174 million).

The Company estimates the undiscounted amount of cash flow required to settle the obligations is

approximately $429 million (2021 – $422 million), which will be incurred between 2023 and 2061. The

majority of these costs will be incurred between 2028 and 2050.

Financial Instruments

The Company is required to determine the fair value of all derivatives except those which qualify for the

normal purchase, normal sale exception. Fair value is the price that would be received for the sale of an

asset or paid to transfer a liability in an orderly arms-length transaction between market participants at the

measurement date. Fair value measurements are required to reflect assumptions that market participants

would use in pricing an asset or liability based on the best available information, including the risks

inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to

the model.

Level Determinations and Classifications

The Company uses Level 1, 2, and 3 classifications in the fair value hierarchy. The fair value

measurement of a financial instrument is included in only one of the three levels and is based on the

lowest level input significant to the derivation of the fair value. Fair values are determined, directly or

indirectly, using inputs that are observable for the asset or liability.

Only in limited circumstances does the

Company enter into commodity transactions involving non-standard features where market observable

data is not available or have contract terms that extend beyond five years.

CHANGES IN ACCOUNTING POLICIES AND

PRACTICES

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

described as follows:

Facilitation of the Effects of Reference Rate Reform on Financial Reporting

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

Reference Rate Reform (Topic

848): Deferral of the Sunset Date of Topic 848

in Q4 2022. The update extends the period of time

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

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

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

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

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

material impact on the consolidated financial statements.

Future Accounting Pronouncements

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

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

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

consolidated financial statements.

SUMMARY OF QUARTERLY

RESULTS

For the quarter ended

millions of dollars

(except per share amounts)

2022

2021

Operating revenues

2,358

1,835

1,380

2,015

1,868

1,148

1,137

1,612

Net income (loss) attributable to

common shareholders

483

167

(67)

362

324

(70)

(17)

273

Adjusted net income

249

203

156

242

168

175

137

243

EPS – basic

1.80

0.63

(0.25)

1.38

1.24

(0.27)

(0.07)

1.08

EPS – diluted

1.80

0.63

(0.25)

1.38

1.20

(0.27)

(0.07)

1.08

Adjusted EPS – basic

0.93

0.76

0.59

0.92

0.64

0.68

0.54

0.96

Quarterly operating revenues and adjusted net income are affected by seasonality. The first quarter

provides strong earnings contributions due to a significant portion of the Company’s operations being in

northeastern North America, where winter is the peak electricity usage season. The third quarter provides

strong earnings contributions due to summer being the heaviest electric consumption season in Florida.

Seasonal and other weather patterns, as well as the number and severity of storms, can affect demand

for energy and the cost of service. Quarterly results could also be affected by items outlined in the

“Significant Items Affecting Earnings” section.