40-F - EMA - Equibles

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM

40-F

☐

REGISTRATION STATEM

ENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934

☒

ANNUAL REPORT PURSUANT TO SECTION 13(a)

OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2021

Commission File Number

000-54516

EMERA INC

ORPORATED

(Exact name of Registrant as specified in its charter)

Nova Scotia

, Canada

(Province or other jurisdiction of incorporation or organization)

4911

(Primary Standard Industrial Classification Code Number (if applicable))

Not applicable

(I.R.S. Employer Identification Number (if applicable))

5151 Terminal Road

Halifax

, Nova Scotia,

Canada

B3J 1A1

Telephone: (

902

)

428-6096

(Address and telephone number of Registrant’s principal executive offices)

Emera US Finance LP

c/o Corporation Service Company

251 Little Falls Drive

Wilmington

Delaware

19808

Telephone: (

302

)

636-5401

(Name, address (including zip code) and telephone number (including area code)

of agent for service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Not applicable.

Securities registered or to be registered pursuant to Section 12(g) of the Act:

Not applicable.

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: Not applicable.

For annual reports, indicate by check mark the information filed with this Form:

☒

Annual information form

☒

Audited annual financial statements

Number of outstanding shares of each of the issuer’s classes of

capital or common stock as of

December 31, 2021

261,065,175

Common Shares

4,866,814

Series A First Preferred Shares

1,133,186

Series B First Preferred Shares

10,000,000

Series C First Preferred Shares

5,000,000

Series E First Preferred Shares

8,000,000

Series F First Preferred Shares

12,000,000

Series H First Preferred Shares

8,000,000

Series J First Preferred Shares

9,000,000

Series L First Preferred Shares

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange

Act during

the preceding 12

months (or for

such shorter period

that the

Registrant was required

to file such

reports) and (2)

has

been subject to such filing requirements for the past 90 days.

Yes

☐

☒

Indicate by

check mark

whether the

registrant has

submitted electronically

and posted

on its

corporate Web

site, if

any,

every

Interactive Data File required to be submitted and

posted pursuant to Rule 405 of Regulation S-T

(§232.405 of this chapter) during

the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).

Yes

☒

☐

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 12b-2 of the Exchange Act.

Emerging growth company

☐

If an emerging growth company that prepares is financial

statements in accordance with U.S. GAAP, indicate by check mark if the

registrant

has

elected

not

use

the

extended

transition

period

for

complying

with

any

new

revised

financial

accounting

standards

†

provided pursuant to Section 13(a) of the Exchange Act.

☐

†

The term “new

or revised financial accounting

standard” refers to

any update issued by

the Financial Accounting Standards

Board

to its Accounting Standards Codification after April 5, 2012.

Indicate

check

mark

whether

the

registrant

has

filed

report

and

attestation

its

management’s

assessment

the

effectiveness of its

internal control over financial

reporting under Section 404(b)

of the Sarbanes-Oxley Act

(15 U.S.C. 7262(b))

by the registered public accounting firm that prepared or issued its audit report.

☐

Certifications and Disclosure Regarding Controls

and Procedures.

(a)

Certifications regarding controls and procedures. See Exhibits 99.5

and 99.6.

(b)

Evaluation of disclosure controls and procedures. As of December 31, 2021, an

evaluation of the

effectiveness of the Registrant’s

“disclosure controls and procedures” (as such term is defined in Rules 13a-

15(e) and 15d-15(e) of the United States Securities Exchange Act of 1934,

as amended (the “Exchange

Act”)), was carried out by the Registrant’s Chief

Executive Officer (“CEO”) and Chief Financial

Officer

(“CFO”). Based on that evaluation, the CEO and CFO have concluded that

as of such date the Registrant’s

disclosure controls and procedures are effective to provide

a reasonable level of assurance that information

required to be disclosed by the Registrant in reports that it files or submits under

the Exchange Act is

recorded, processed, summarized and reported within the time periods

specified in United States Securities

and Exchange Commission (the “Commission”) rules and forms.

It should be noted that while the CEO and CFO believe that the Registrant’s

disclosure controls and

procedures provide a reasonable level of assurance that they are effective,

they do not expect the disclosure

controls and procedures or internal control over financial reporting to be capable

of preventing all errors

and fraud. A control system, no matter how well conceived or operated,

can provide only reasonable, not

absolute, assurance that the objectives of the control system are met.

(c)

Management’s annual report

on internal control over financial reporting.

The Registrant's management is

responsible for establishing and maintaining adequate internal control

over financial reporting. The

Registrant'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. The Registrant's management,

including the CEO and CFO, evaluated the

design and effectiveness of the Registrant's internal control over

financial reporting as at December 31,

2021 and concluded that the Registrant's internal control over financial

reporting is effective as at

December 31, 2021.

(d)

Attestation report of the registered public accounting firm.

This annual report does not include an

attestation report of the Registrant’s

registered public accounting firm regarding internal control over

financial reporting.

(e)

Changes in internal control over financial reporting. There were no changes

in the Registrant’s internal

control over financial reporting during the fiscal year ended December

31, 2021, that have materially

affected, or are reasonably likely to materially affect,

the Registrant’s internal control

over financial

reporting.

Audit Committee Financial Expert.

The Registrant’s board of directors

(the “Board”) has determined that four

audit committee financial experts serve on its Audit Committee. The audit

committee financial experts are Kent M.

Harvey, B. Lynn

Loewen, Andrea S. Rosen and Richard P.

Sergel. The Board has determined that Kent M. Harvey,

B. Lynn Loewen, Andrea S. Rosen

and Richard P.

Sergel are independent within the meaning of the listing

standards of the New York

Stock Exchange. Information concerning the relevant experience of Kent M. Harvey,

Lynn Loewen, Andrea S. Rosen

and Richard P.

Sergel is included in their biographical information contained in the

Registrant’s Annual Information

Form for the fiscal year ended December 31, 2021, filed as Exhibit 99.1 hereto (the

“Annual Information Form”). The Commission has indicated that the

designation of a person as an audit committee

financial expert does not make such person an “expert” for any purpose,

impose any duties, obligations or liability

on such person that are greater than those imposed on members of the audit committee

and board of directors who

do not carry this designation, or affect the duties, obligations or

liability of any other member of the audit committee

or board of directors.

Code of Ethics.

The Emera Code of Conduct was revised and became effective

on February 1, 2021 (the “Code”)

and applies to all directors, officers and employees of the Registrant, including

the CEO and CFO. Since the

adoption of the Code, there have not been any waivers, including implied waivers,

from any provision of the Code.

A copy of the Code can be found on Emera’s

internet website at the following address:

https://www.emera.com/about

-us/who-we-are/code-of-conduct.

The Code was furnished to the Commission on February 24, 2021

as Exhibit 99.1 to a report on Form 6-K and is

incorporated by reference herein as Exhibit 99.9.

Principal Accountant Fees and Services.

The information provided under the headings “Audit Committee—Audit

and Non-Audit Services Pre-Approval Process” and “Audit Committee—Auditors’

Fees” contained in the

Registrant’s Annual Information

Form. The Registrant’s Audit Committee approved

all of the Audit-Related and

Tax services provided

by Ernst & Young

LLP in 2021 and none were approved pursuant to the de minimus

exception provided by Section (c)(7)(i)(C) of Rule 2-01 of Regulation

S-X.

In connection with the U.S. Securities and Exchange Commission’s

adoption of amendments to finalize the

implementation of disclosure and submission requirements on

December 2, 2021, pursuant to Release No. 34-

93701, the Registrant hereby affirms that

Ernst & Young LLP

(PCAOB ID:

1263

) delivered an audit opinion

relating to the Registrant’s Financial Statements

(as defined below) contained in the Annual Information

Form, and

such audit opinion was issued in

Halifax, Nova Scotia

, Canada.

Liquidity and Capital Resources

The information provided under the headings (a) “Off-Balance Sheet

Arrangements” and (b) “Contractual

Obligations” contained in the Registrant’s

Management’s Discussion and

Analysis dated February 14, 2022 for the

year ended December 31, 2021, filed as Exhibit 99.2 hereto (the “MD&A”) and with

respect to clause (a) the

information provided at note 27 (“D. Guarantees and Letters of Credit”) and note

32 (“Variable

Interest Entities”),

and with respect to clause (b) note 27 (“A. Commitments”) and note 25 (“Long-Term

Debt”), to the Audited

Consolidated Financial Statements as at and for the years ended December 31, 2021

and December 31, 2020, filed

as Exhibit 99.3 hereto (the “Financial Statements”), are incorporated by reference

herein.

Identification of the Audit Committee.

The information provided under the heading “Audit Committee” contained

in the Annual Information Form is incorporated by reference herein.

Mine Safety Disclosure.

Neither the Registrant nor any of its subsidiaries is the “operator” of

any “coal or other

mine”, as those terms are defined in section 3 of the Federal Mine Safety and Health Act of 1977

(30 U.S.C. 802),

that is subject to the provisions of such Act (30 U.S.C. 801 et seq.). Therefore, the

provisions of Section 1503(a) of

the Dodd-Frank Wall

Street Reform and Consumer Protection Act and Item 16 of General Instruction

B to Form 40-

F requiring disclosure concerning mine safety violations and other

regulatory matters do not apply to the Registrant

or any of its subsidiaries.

EXHIBIT INDEX

Exhibit

Number

Description

99.1

2021 Annual Information Form dated February 14, 2022 for the fiscal year ended

December 31,

2021

99.2

Management’s Discussion and Analysis

dated February 14, 2022 for the year ended December

31, 2021

99.3

Audited Consolidated Financial Statements as at and for the years ended

December 31, 2021 and

December 31, 2020

99.4

Consent of Independent Registered Public Accounting Firm

99.5

Certification of Chief Executive Officer pursuant

to Rule 13a-14(a) or 15d-14(a) of the U.S.

Securities Exchange Act of 1934, as amended

99.6

Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d

-14(a) of the U.S.

Securities Exchange Act of 1934, as amended

99.7

Certification of Chief Executive Officer pursuant to Section 906

of the Sarbanes-Oxley Act of

2002

99.8

Certification of Chief Financial Officer pursuant to Section 906

of the Sarbanes-Oxley Act of

2002

99.9

Emera Code of Conduct (as revised on February 1, 2021) (incorporated by reference

to Emera

Incorporated’s Form 6-K, furnished

to the Commission on February 24, 2021)

101

Interactive Data File (formatted as inline XBRL)

104

Cover Page Interactive Data File (formatted as Inline XBRL and contained

in Exhibit 101)

UNDERTAKING

AND CONSENT TO SERVICE OF PROCESS

The Registrant undertakes to make available, in person or by telephone, representatives

to respond to inquiries made

by the Commission staff, and to furnish promptly,

when requested to do so by the Commission staff, information

relating to the securities in relation to which the obligation to file an annual report on

Form 40-F arises or

transactions in said securities.

The Registrant has previously filed a Form F-X in connection with the class of

securities in relation to which the

obligation to file this report arises.

Any change to the name or address of a Registrant’s

agent for service shall be communicated promptly to the

Commission by amendment to Form F-X referencing the file number of

the Registrant.

SIGNATURES

Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of

the requirements for

filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned,

thereto

duly authorized.

DATED

this 14

day of February, 2022.

EMERA

INCORPORATED

By:

/s/ Scott C. Balfour

Name:

Scott C. Balfour

Title:

President & Chief

Executive Officer

EX-99.1

Exhibit 99.1

LOGO

Emera Incorporated

Annual Information Form

For the year ended December 31, 2021

February 14, 2022

ANNUAL INFORMATION FORM

For the year ended December 31, 2021

Dated: February 14, 2022

TABLE OF CONTENTS

PRESENTATION OF INFORMATION	4
CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION	4
CORPORATE STRUCTURE	6
Name and Incorporation	6
Amended Articles of Association	6
Intercorporate Relationships	6
INTRODUCTION	7
COVID-19 Pandemic	8
DESCRIPTION OF THE BUSINESS	9
Business Segments	9
Florida Electric Utility	9
Canadian Electric Utilities	13
Other Electric Utilities	16
Gas Utilities and Infrastructure	19
Other	22
GENERAL DEVELOPMENT OF THE BUSINESS	23
Florida Electric Utility	23
Canadian Electric Utilities	24
Other Electric Utilities	26
Gas Utilities and Infrastructure	27
Other	28
Removal of Legislative Restriction on Non-Canadian Resident Ownership	28
USGAAP – Exemptive Relief and Companies Act Relief	28
Financing Activity	29
RISK FACTORS	30
CAPITAL STRUCTURE	30
Common Shares	30
Emera First Preferred Shares	31
Emera Second Preferred Shares	31
Share Ownership Restrictions	31
CREDIT RATINGS	32
DIVIDENDS	34
MARKET FOR SECURITIES	35
Trading Price and Volume	35
At-The-Market Equity Program	35
Emera Incorporated – 2021 Annual Information Form	2
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DIRECTORS AND OFFICERS	36
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Directors	36
Officers	38
AUDIT COMMITTEE	39
Audit and Non-Audit Services Pre-Approval Process	40
Auditors’ Fees	40
CERTAIN PROCEEDINGS	40
CONFLICTS OF INTEREST	41
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	41
NO INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	41
MATERIAL CONTRACTS	41
TRANSFER AGENT AND REGISTRAR	41
EXPERTS	42
ADDITIONAL INFORMATION	42
APPENDIX “A” - DEFINITIONS OF CERTAIN TERMS	43
APPENDIX “B” – SUMMARY OF TERMS AND CONDITIONS OF AUTHORIZED SERIES OF FIRST PREFERRED SHARES	48
APPENDIX “C” - MONTHLY TRADING VOLUME AND HIGH AND LOW PRICE FOR EMERA’S SECURITIES IN 2021	51
APPENDIX “D” - EMERA INCORPORATED AUDIT COMMITTEE CHARTER	52
Emera Incorporated – 2021 Annual Information Form	3
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PRESENTATION OF INFORMATION

Unless otherwise noted, the information contained in this Annual Information Form (“AIF”) is given at or for the year ended December 31, 2021. Amounts are expressed in Canadian dollars unless otherwise indicated. All financial information presented in millions of Canadian dollars is rounded to the nearest million unless otherwise stated. Unless otherwise indicated, all financial information is presented in accordance with United States’ generally accepted accounting principles (“USGAAP”). Emera Incorporated (“Emera” or “the Company”) uses Adjusted Net Income Attributable to Common Shareholders (“adjusted net income”) as a financial performance measure, which is not a defined financial measure according to USGAAP and does not have standardized meanings prescribed by USGAAP. For further information on the non-GAAP financial measure, adjusted net income, including a full description of the measure and a reconciliation to the nearest USGAAP measure, please refer to the Company’s MD&A section entitled “Non-GAAP Financial Measures”, which is incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

Certain capitalized terms used herein, and not otherwise defined herein, are defined under “Definitions of Certain Terms”, attached to this AIF as Appendix “A”. Reference to “including”, “include”, or “includes” means “including (or includes) but is not limited to” and shall not be construed to limit any general statement preceding it to the specific or similar items or matters immediately following it.

This AIF provides material information about the business and operations of Emera. The “Enterprise Risk and Risk Management” section of the Company’s MD&A is incorporated herein by reference and can be found on SEDAR at www.sedar.com.

CAUTIONARY NOTE REGARDINGFORWARD-LOOKING INFORMATION

This AIF, including the documents incorporated herein by reference, contains “forward-looking information” and “forward-looking statements” within the meaning of applicable securities laws (collectively, “forward-looking information”). 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. References to “Emera” in this section include references to the subsidiaries of Emera.

The forward-looking information in this AIF, including the documents incorporated herein by reference, includes statements which reflect the current view of Emera’s management with respect to Emera’s objectives, plans, financial and operating performance, carbon dioxide emissions reduction goals, business prospects and opportunities. 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(s) at which, such events, performance or results will be achieved. All such forward-looking information in this AIF is provided pursuant to safe harbour provisions contained in applicable securities laws.

The forward-looking information in this AIF, including the documents incorporated herein by reference, includes, but is not limited to, statements regarding: Emera’s revenue, earnings and cash flow; the growth and diversification of Emera’s business and earnings base; future annual net income and dividend growth; expansion of Emera’s business; the expected compliance by Emera with the regulation of its operations; the expected timing of regulatory decisions; forecasted capital investments; the nature, timing and costs associated with certain capital projects; the expected impact on Emera of challenges in the global economy; estimated energy consumption rates; expectations related to annual operating cash flows; the expectation that Emera will continue to have reasonable access to capital in the near to medium term; expected debt maturities, repayments and renewals; expectations about increases in interest expense and/or fees associated with debt securities and credit facilities; no material adverse credit rating actions expected in the near term; the successful development of relationships with various stakeholders, the impact of currency fluctuations; expected changes in electricity rates; and the impacts of planned investment by the industry of gas transportation infrastructure within the United States.

Emera Incorporated – 2021 Annual Information Form	4

The forecasts and projections that make up the forward-looking information are based on reasonable assumptions which include, but are not limited to: the receipt of applicable regulatory approvals and requested rate decisions; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather or global climate change, other acts of nature or other major events; seasonal weather patterns remaining stable; no significant cyber or physical attacks or disruptions to Emera’s systems; the continued ability to maintain transmission and distribution systems to ensure their continued performance; continued investment in solar, wind and hydro generation; continued natural gas activity; no severe and/or prolonged downturn in economic conditions; sufficient liquidity and capital resources; the continued ability to hedge exposures to fluctuations in interest rates, foreign exchange rates and commodity prices; no significant variability in interest rates; expectations regarding the nature, timing and costs of capital investments of Emera and its subsidiaries; expectations regarding rate base growth; the continued competitiveness of electricity pricing when compared with other alternative sources of energy; the continued availability of commodity supply; the absence of significant changes in government energy plans and environmental laws and regulations that may materially affect Emera’s operations and cash flows; maintenance of adequate insurance coverage; the ability to obtain and maintain licenses and permits; no material decrease in market energy sales prices; favourable labour relations; and sufficient human resources to deliver service and execute Emera’s capital investment plan.

The forward-looking information 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, but are not limited to: regulatory 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; the 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; counterparty risk; disruption of fuel supply; country risks; environmental risks; foreign exchange; 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 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 AIF and in the documents incorporated herein by reference 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.

Emera Incorporated – 2021 Annual Information Form	5

CORPORATE STRUCTURE

Name and Incorporation

Emera was incorporated on July 23, 1998 pursuant to the Companies Act (Nova Scotia). The Reorganization Act and the Privatization Act require the Company’s Articles of Association (the “Articles”) to contain provisions specifying that the head office and the principal executive offices of the Company are to be situated in the Province of Nova Scotia. The current address of the Company’s registered office, head office and principal executive offices is Emera Place, 5151 Terminal Road, Halifax, Nova Scotia, Canada, B3J 1A1.

Amended Articles of Association

On April 12, 2019, amendments to the Privatization Act and the Reorganization Act were enacted, removing the legislative restriction preventing non-Canadian residents from holding more than 25 per cent of Emera voting shares, in aggregate. The Board approved amendments to the Articles and on July 11, 2019, shareholders passed a special resolution to amend the Articles to remove this restriction. For more information on these amendments to the Articles, please refer to Emera’s Management Information Circular dated May 31, 2019 distributed in connection with a special meeting of shareholders held on July 11, 2019, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

Intercorporate Relationships

The following table sets forth the relationships among the Company and its principal subsidiaries, the percentage of votes attaching to all voting securities of its respective subsidiaries beneficially owned, or controlled or directed, directly or indirectly, by the Company, as well as their respective jurisdictions of incorporation, continuance, formation or organization. This table excludes certain subsidiaries, the assets and revenues of which did not individually exceed 10 per cent, or in the aggregate exceed 20 per cent, of the total consolidated assets or total consolidated revenues of the Company as at December 31, 2021.

Subsidiaries	Percentage Ownership<br><br><br>(%)	Jurisdiction
Tampa Electric Company^1^	100	Florida
Nova Scotia Power	100	Nova Scotia
New Mexico Gas Company	100	Delaware
(1)	Tampa Electric Company (TEC) includes both its regulated electric and gas utilities, namely the Tampa Electric Division<br>and the Peoples Gas System (PGS) Division.
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Emera Incorporated – 2021 Annual Information Form	6
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INTRODUCTION

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.

Emera’s investment in rate-regulated businesses is concentrated in Florida and Nova Scotia. These service areas have generally experienced stable regulatory policies and economic conditions. 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 ROE as approved through regulation. Earnings are also affected by sales volumes and operating expenses.

Emera’s capital investment plan is $8.4 billion over the 2022-to-2024 period (including a $240 million equity investment in the LIL in 2022), with an additional $1 billion of potential capital investments over the same period. This results in a forecasted rate base growth of approximately 7 per cent to 8 per cent through 2024. 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 and ATM Program. Maintaining investment-grade credit ratings is a priority of management.

Emera has provided annual dividend growth guidance of four to five per cent through 2024. 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” section of the MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

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 US dollar relative to the Canadian dollar and benefit from a weaker Canadian dollar. Emera may hedge both transactional and translational exposure. These impacts, as well as the timing of capital investments and other factors, mean that 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 sees opportunity 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.

Emera Incorporated – 2021 Annual Information Form	7

For example, significant investments to facilitate the use of renewable and low-carbon energy include the Maritime Link in Atlantic Canada, the ongoing construction of solar generation and modernization of the Big Bend Power Station at Tampa Electric and planned NSPI investments to enable the retirement of its coal units and to achieve renewable energy targets. 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 over the past 15 years, 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 the benefit of supportive regulatory decisions, Emera plans and expects to achieve the following goals compared to corresponding 2005 levels:

·	A 55 per cent reduction in carbon dioxide emissions by 2025.
·	An 80 per cent reduction in coal usage by 2023 and the retirement of Emera’s last existing coal unit no later<br>than 2040.
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·	At least an 80 per cent reduction in carbon dioxide emissions by 2040.
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Emera seeks to deliver on its Climate Commitment while maintaining its focus on investing in reliability and never losing sight of affordability 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.

COVID-19 Pandemic

While the ongoing COVID-19 pandemic continues to have varying effects on the service territories in which Emera operates, on a consolidated basis, COVID-19 did not have a material financial impact on net income in 2021. Capital project delays and supply chain disruptions have also been minimal. The Company continues to monitor developments, economic conditions and recommendations by local and national public health authorities related to COVID-19 and is adjusting operational requirements as needed.

The extent of the future impact of COVID-19 on the Company’s financial results and business operations cannot be predicted at this time but is not expected to have a material financial impact in 2022. Future impacts will depend on a variety of factors, including the duration and severity of the pandemic, timing and effectiveness of vaccinations, further government actions and future economic activity and energy usage. Potential future impacts of COVID-19 on the business may include the following:

·	Lower earnings as a result of lower sales volumes due to economic slowdowns and the pace and strength of economic<br>recovery;
·	Delays of capital projects as a result of construction shutdowns, government restrictions on non-essential capital work,<br>travel restrictions for contractors or supply chain disruptions;
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·	Deferral of and adjustment to regulatory filings, hearings, decisions and recovery periods; and
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·	Decreased cash flow from operations due to lower earnings and slower collection of accounts receivable or increased<br>credit losses.
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Emera Incorporated – 2021 Annual Information Form	8
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The Company currently expects to continue to have adequate liquidity given its cash position, existing bank facilities, and access to capital, but will continue to monitor the impact of COVID-19 on future cash flows. For further detail, refer to the “Liquidity and Capital Resources” section of the MD&A and for affiliate specific impacts of COVID-19, if applicable, refer to the outlook sections of the MD&A, by segment, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

DESCRIPTION OF THE BUSINESS

Business Segments

Emera’s reportable segments are:

·	Florida Electric Utility, which consists of Tampa Electric;
·	Canadian Electric Utilities, which includes NSPI and ENL, a holding company with equity investments in NSPML (100<br>per cent) and the LIL (37.4 per cent);
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·	Other Electric Utilities, which includes ECI, a holding company with regulated electric utilities which include<br>BLPC, GBPC, a 51.9 per cent interest in Domlec and a 19.5 per cent equity interest in Lucelec. On March 24 2020, Emera completed the sale of Emera Maine, which was previously included in this segment;
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·	Gas Utilities and Infrastructure, which includes PGS, NMGC, SeaCoast, Emera Brunswick Pipeline Company and an<br>equity investment in M&NP; and
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·	Other, which includes Emera Energy, ETL and corporate holding, financing companies and certain other investments.<br>
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General

Emera and its subsidiaries had 7,140 employees as at December 31, 2021, approximately 33 per cent of whom are unionized.

Emera has grown its business through its rate-regulated subsidiaries and other equity investments, which include:

·	Tampa Electric (see “Florida Electric Utility” section below);
·	NSPI (see “Canadian Electric Utilities” section below);
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·	BLPC, GBPC and Domlec (see “Other Electric Utilities” section below);
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·	PGS, NMGC, SeaCoast, Emera Brunswick Pipeline Company (see “Gas Utilities and Infrastructure” section below);<br>
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·	Emera’s 100 per cent investment in Maritime Link (see “Canadian Electric Utilities” section below);<br>
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·	Emera’s 37.4 per cent investment in the partnership capital of LIL (see “Canadian Electric<br>Utilities” section below); and
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·	a 12.9 per cent interest in M&NP (see “Gas Utilities and Infrastructure” section below).<br>
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Operations by Segment

The following sections describe the operations included in each of the Company’s reportable segments.

Florida Electric Utility

Emera Incorporated – 2021 Annual Information Form	9

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 occur at the initiative of Tampa Electric, the FPSC or other interested parties.

Market and Sales

Tampa Electric Revenue and Sales by Customer Class
	Electric Revenues (%)		GWh Electric Sales Volumes (%)
For the year ended December 31	2021	2020	2021	2020
Residential	53.2.	55.0	49.2	50.6
Commercial	27.7	27.4	30.4	30.2
Industrial	7.9	7.2	10.50	9.4
Other	11.2	10.4	9.9	9.8
Total	100.0	100.0	100.0	100.0

Energy sources and generation

As at December 31, 2021, Tampa Electric owns 5,919 MW of generating capacity, of which 77 per cent is natural gas-fired, 12 per cent is solar and 11 per cent is coal. Tampa Electric owns 2,165 kilometres of transmission facilities and 19,530 kilometres of distribution facilities.

Beginning in 2022, Tampa Electric’s approved regulated ROE range is 9.00 per cent to 11.00 per cent, based on an allowed equity capital structure of 54 per cent (2021 – 9.25 per cent to 11.25 per cent based on an allowed equity capital structure of 54 per cent). An ROE of 9.95 per cent (2021 – 10.25 per cent) will be used for the calculation of the return on investments for clauses.

System Operations

Tampa Electric’s Energy Control Center co-ordinates and controls the electric generation, transmission and distribution facilities. The Energy Control Center is linked to the generating stations and other key facilities through the Supervisory Control and Data Acquisition system, a communication network used by system operators for remote monitoring and control of the power system assets.

Through interconnection agreements with our neighboring electric utilities within the Florida Region, Tampa Electric’s system has access to other regional power systems and the rest of the interconnected North American electric bulk power system. The interconnection of power systems enhances the cost effectiveness, reserve capacity and reliability of participating power systems. As a member of the Florida Reserve Sharing Group, Tampa Electric has immediate access to reserve generating capacity from all other group members.

Fuel Recovery Clause

Tampa Electric has a fuel recovery clause approved by the FPSC, allowing the opportunity to recover fluctuating fuel expenses from customers through annual fuel rate adjustments. Differences between prudently incurred fuel costs and amounts recovered from customers through electricity rates in a year are deferred to a fuel clause regulatory asset or liability and recovered from or returned to customers in a subsequent year.

Storm Protection Plan Cost Recovery Clause

Tampa Electric has a Storm Protection Plan cost recovery clause allowing recovery of prudent transmission and distribution storm hardening costs for incremental activities not already included in base rates as outlined in the programs in its approved Storm Protection Plan. Differences between prudently incurred clause-recoverable costs and amounts recovered from customers through electricity rates in a year are deferred and recovered from or returned to customers in a subsequent year.

Emera Incorporated – 2021 Annual Information Form	10

Other Cost Recovery Clauses

The FPSC annually approves cost-recovery rates for purchased power, capacity, environmental and conservation costs, including a return on capital invested. Differences between prudently incurred clause-recoverable costs and amounts recovered from customers through electricity rates in a year are deferred to a corresponding regulatory asset or liability and recovered from or returned to customers in a subsequent year.

Capital Cost Recovery for Early Retired Assets

Tampa Electric also has a regulatory asset related to the remaining net book value of Big Bend Power Station Units 1 through 3 and smart meter assets that were retired. This capital cost recovery for early retired assets is authorized by and survives the term of the settlement agreement approved by the FPSC in 2021. For more information, refer to the “Regulatory Environments – Big Bend Modernization Project” section of Note 7, Regulatory Assets and Liabilities, to the Audited Financial Statements, which are hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

Storm Reserve

The storm reserve is for hurricanes and other named storms that cause significant damage to Tampa Electric’s system. Tampa Electric can petition the FPSC to seek recovery of restoration costs over a 12-month period, or longer, as determined by the FPSC, as well as to replenish the reserve.

Contribution to Consolidated Net Income

Florida Electric Utility’s contribution to consolidated net income was $369 million USD in 2021 (2020 - $372 million USD).

Seasonal Nature

Electric sales volumes are primarily driven by general economic conditions, population and weather. Residential and commercial electricity sales are seasonal. In Florida, Q3 is the strongest period for electricity sales, reflecting warmer weather and cooling demand.

Capital Investments

In 2021, capital investments (including AFUDC) in the Florida Electric Utility segment were $1.2 billion USD (2020 – $1.0 billion USD). In 2022, capital investment is expected to be approximately $1.1 billion USD, including AFUDC. Capital projects include continuation of the modernization of the Big Bend Power Station, solar investments, grid modernization and storm hardening investments.

As of December 31, 2021, Tampa Electric has invested $850 million USD in 600 MW of utility-scale solar photovoltaic projects, which are recoverable through FPSC-approved SoBRAs. For further information on this investment, refer to the “General Developments of the Business” section below.

Tampa Electric has invested approximately $695 million USD through December 31, 2021 to modernize the Big Bend Power Station.. For further information on this investment, refer to the “General Developments of the Business” section below.

Environmental Considerations

Tampa Electric has an ECRC, which allows the company to earn a return on investments in infrastructure required to comply with new environmental regulations, including those discussed below, and to recover the costs to operate and maintain these facilities. Through the ECRC, Tampa Electric also offers its customers a comprehensive array of residential and commercial programs that have enabled the company to meet its required demand side management goals, reduce weather-sensitive peak demand and conserve energy.

Emera Incorporated – 2021 Annual Information Form	11

Tampa Electric operates stationary sources with air emissions regulated by the Clean Air Act. Its operations are also impacted by provisions in the Clean Water Act and federal and state legislative initiatives on environmental matters.

Hazardous Air Pollutants

All of Tampa Electric’s conventional coal-fired units are already equipped with electrostatic precipitators, scrubbers and selective catalytic reduction systems, and the Polk Unit 1 integrated gasification combined-cycle unit emissions are minimized in the gasification process. Therefore, Tampa Electric has minimized the impact of the EPA’s current Mercury Air Toxics Standards (MATS) and has demonstrated compliance with the most stringent “Low Emitting Electric Generating Unit” classification for the EPA’s current MATS with nominal additional capital investment.

Carbon Reductions and GHG

In June 2019, the EPA released a final rule, named the Affordable Clean Energy (ACE) rule, to establish emission guidelines for states to address GHG emissions from existing coal-fired electric generating units (EGUs). A replacement rule is currently under development as a result of a legal challenge. Compliance with the terms of the ACE new rule, once adopted and finalized, could cause an increase in costs or rates charged to customers, which could curtail sales.

Tampa Electric expects that the costs to comply with new environmental regulations would be eligible for recovery through the ECRC. If approved as prudent, the costs required to comply with CO2 emissions reductions would be reflected in customers’ bills. If the regulation allowing cost recovery is changed and the cost of compliance is not recovered through the ECRC, Tampa Electric could seek to recover those costs through a base-rate proceeding.

Ozone

On December 31, 2020, the EPA published a final rule to retain the national ambient air quality standards (NAAQS) for photochemical oxidants including ozone, originally adopted in 2012. Under the Clean Air Act, the EPA is required to review the NAAQS every five years and, if appropriate, revise it. The EPA has announced that the NAAQS is currently under review, which could result in revisions to the standard affecting compliance in Tampa Electric’s service territory. The impact of this potential new standard on the operations of Tampa Electric will depend on the standard that is ultimately adopted and on the outcome of any related litigation or other developments.

WaterSupply and Quality

The EPA’s final rule under 316(b) of the Clean Water Act (effective October 2014) addresses perceived impacts to aquatic life by cooling water intakes and is applicable to Tampa Electric’s Bayside and Big Bend Power Stations. The full impact of the regulations on Tampa Electric will depend on the results of the study elements performed as part of the rules’ implementation, and the actual requirements established by Florida Department of Environmental Protection.

The final EPA rule for existing steam electric effluent limit guidelines (ELGs) became effective January 4, 2016 and establishes limits for certain wastewater discharges. The ELGs are expected to be incorporated into National Pollutant Discharge Elimination System (NPDES) permit renewals for Big Bend Station and Polk Power Station to achieve compliance as soon as possible after November 1, 2018, but no later than December 31, 2023.

Emera Incorporated – 2021 Annual Information Form	12

The preliminary draft of the NPDES Permit for Big Bend stated that effluent limitations for total recoverable arsenic, mercury, and selenium and total nitrate/nitrite for flue gas desulfurization wastewater are applicable no later than December 31, 2023. The effluent limitations do not apply to Polk Power Station.

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 a 100 per cent equity investment in NSPML and a 37.4 per cent equity investment in 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

NSPI is the primary electricity supplier in Nova Scotia, providing electricity generation, transmission and distribution services to approximately 536,000 customers with $6.1 billion in assets and 2,105 employees as at December 31, 2021.

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.

NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers and provide a reasonable return to investors. NSPI’s approved regulated ROE range for 2021 and 2020 was 8.75 per cent to 9.25 per cent based on an actual five quarter average regulated common equity component of up to 40 per cent.

NSPI has a FAM, approved by the UARB, allowing NSPI to recover fluctuating fuel costs from customers through fuel rate adjustments. Differences between prudently incurred fuel costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability.

NSPI is currently operating under a three-year fuel stability plan which results in an average annual overall rate increase of 1.5 per cent to recover fuel costs for the period of 2020 through 2022. These rates include recovery of Maritime Link costs. Pursuant to the FAM plan of administration, NSPI’s fuel costs are subject to independent audit.

Market and Sales

NSPI Revenue and Electricity Sales by CustomerClass
	Electric Revenues (%)		GWh Electric Sales Volumes (%)
For the year ended December 31	2021	2020	2021	2020
Residential	54.3	55.0	45.7	46.5
Commercial	27.7	27.6	28.5	28.4
Industrial	16.1	15.3	24.3	23.3
Other	1.9	2.1	1.5	1.8
Total	100.0	100.0	100.0	100.0

Energy Sources and Generation

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 petroleum coke and 2 per cent is biomass-fueled generation, supplemented by 546 MW contracted with IPPs, including COMFIT participants.

Emera Incorporated – 2021 Annual Information Form	13

System Operations

NSPI’s Control Center Operations co-ordinates and controls the electric generation, transmission and distribution facilities. The Control Center is linked to the generating stations and other key facilities through the Supervisory Control and Data Acquisition system, a communication network used by system operators for remote monitoring and control of the power system assets.

Through interconnection agreements with NB Power and with Newfoundland and Labrador Hydro, NSPI’s system has access to other regional power systems and the rest of the interconnected North American electric bulk power system. The interconnection of power systems enhances the cost effectiveness, reserve capacity and reliability of participating power systems. The interconnection agreements also provide participating utilities with a source of reserve power, subject to availability and the requirements of the supplier.

Transmission and Distribution

NSPI transmits and distributes electricity from its generating stations to its customers. NSPI’s transmission system consists of approximately 5,000 km of transmission facilities. The distribution system consists of approximately 28,000 km of distribution facilities, which includes distribution supply substations.

ENL

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 with Nalcor forecasting it will achieve final commissioning in the first half of 2022. 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 at a date to be agreed to by the companies.

NSPML received UARB approval to collect up to $172 million (2020 - $145 million) from NSPI for the recovery of costs associated with the Maritime Link in 2021. This was subject to a holdback of up to $10 million that was dependent upon the timing of commencement of the NS Block. On January 18, 2022, the UARB directed NSPI to pay to NSPML approximately $10 million of the 2021 holdback. NSPML has deferred collection and recognition of $23 million in depreciation expense in 2021. Approximately $162 million is included in NSPI rates in 2022.

On August 9, 2021, NSPML filed a final capital cost application with the UARB seeking approval to recover capital costs associated with the Maritime Link and approval of NSPML’s 2022 assessment. In December 2021, NSPML obtained an interim decision from the UARB approving interim rates beginning January 1, 2022, until receipt of the UARB’s decision on the application. On February 9, 2022, the UARB issued its decision relating to the Maritime Link project, approving NSPML’s requested rate base of approximately $1.8 billion less costs that would not otherwise have been recoverable if incurred by NSPI. The UARB also approved approximately $168 million of NSPML revenue requirement in 2022 subject to a holdback of $2 million per month beginning April 1, 2022 and thereafter to the end of the year. This holdback is to be used to fund any replacement energy costs incurred by NSPI due to a 10 per cent or greater shortfall in contracted NS Block deliveries each month and will otherwise be released to NSPML. NSPML is required to provide the UARB with a compliance filing by February 16, 2022 which will confirm the impacts of this decision including the amount of the unrecoverable items which are not expected to exceed $10 million (pre-tax).

Emera Incorporated – 2021 Annual Information Form	14

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 the first half of 2022.

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 $682 million, comprised of $410 million in equity contribution and $272 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 all Lower Churchill projects are completed.

Cash earnings and return of equity will begin after commissioning of the LIL by Nalcor, which is anticipated in the first half of 2022, and until that point Emera will continue to record AFUDC earnings.

Contribution to Consolidated Net Income

Canadian Electric Utilities contribution to Emera’s consolidated net income was $241 million in 2021 (2020 - $221 million).

Seasonal Nature

Electric sales volumes are primarily driven by weather, number of customers, general economic conditions, and demand side management activities. Residential and commercial electricity sales are seasonal in Nova Scotia, with the first quarter historically generating the highest sales, reflecting colder weather and fewer daylight hours in the winter season.

Capital Investment

NSPI

NSPI’s capital investments in 2021 were $388 million (2020 - $316 million), including AFUDC. In 2022, NSPI expects to invest $530 million, including AFUDC, primarily in capital projects to support system reliability, renew hydroelectric infrastructure, and increase renewable energy.

NSPML

NSPML’s capital investments in 2021 were $6 million (2020 – $7 million). In 2022, NSPML expects to invest approximately $5 million in capital.

Environmental Considerations

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 reductions will be recoverable under NSPI’s regulatory framework.

Over the past several years, the requirement to reduce Nova Scotia’s reliance on higher carbon and GHG emitting sources of energy has resulted in NSPI making significant investments in renewable energy sources, including energy from the Maritime Link, and purchasing renewable energy from IPPs.

Emera Incorporated – 2021 Annual Information Form	15

In Q1 2021, NSPI received its 2021 granted emissions allowances under the Nova Scotia Cap-and-Trade Program Regulations. These 2021 allowances will be used in 2021 or allocated within the initial four-year compliance period that ends in 2022. In addition to the granted allowances, NSPI 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. Reserve credits are anticipated to be priced at a premium to provincial auction pricing. Compliance is forecast to be achieved through granted emissions allowances, reduced emissions partly due to delivery of energy from the Muskrat Falls hydroelectric project (“Muskrat Falls”), and credit purchases under the Cap-and-Trade Program, including reserve credits. NSPI anticipates that any prudently incurred costs required to comply with the Government of Canada’s laws and regulations, and the Nova Scotia Cap-and-Trade Program Regulations, will be recoverable under NSPI’s regulatory framework.

Renewable Energy from Maritime Link Project

Energy from renewable sources has increased with Nalcor’s NS Block delivery obligations from Muskrat Falls commencing August 15, 2021. Nalcor will provide NSPI with approximately 900 GWh of energy annually over 35 years. In addition, for the first five years of the NS Block, NSPI is also entitled to receive approximately 240 GWh of additional energy from the Supplemental Energy Block transmitted through the Maritime Link. As Nalcor is in the final stages of commissioning the LIL, there will be periodic commissioning related interruptions in supply with any resultant delivery shortfalls being delivered at a date to be agreed to by the companies. Commencing in September 2022, NSPI has the option of purchasing additional market-priced energy from Nalcor through the Energy Access Agreement. Pursuant to the Energy Access Agreement, Nalcor is obligated to offer NSPI a minimum average of 1.2 TWh of energy annually. Nalcor is forecasting it will achieve final commissioning of the Lower Churchill projects (including Muskrat Falls and LIL) in the first half of 2022.

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 in 2020, as permitted by the legislation. The alternative compliance plan requires NSPI to supply customers with at least 40 per cent of energy generated from renewable sources over the 2020 through 2022 period. With full delivery of the NS Block having only recently commenced, NSPI’s ability to achieve 40 per cent of total sales from renewable sources over the 2020 through 2022 period may be at risk. If NSPI is found not to have acted in a duly diligent manner, it could be subject to a maximum penalty of $10 million. As 2022 progresses, NSPI will monitor its progress toward achieving the 40 per cent standard and, as per the requirements of the Renewable Energy Regulations, NSPI intends to act in a duly diligent manner.

Other Environmental Legislation and Regulations

There have been several recent environmental developments at both the federal and provincial levels, as described below in the “General Development of the Business – Canadian Electric Utilities - NSPI” section. For additional information on environmental regulations affecting NSPI, see NSPI’s 2021 Annual Information Form, a copy of which is available electronically under NSPI’s profile on SEDAR at www.sedar.com.

Other Electric Utilities

Other Electric Utilities includes 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, a 51.9 per cent interest in Domlec on the island of Dominica 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 24, 2020, Emera completed the sale of Emera Maine. For further detail, refer to the “Significant Items Affecting Earnings” sections of Emera’s MD&A, incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.emera.com.

Emera Incorporated – 2021 Annual Information Form	16

Market and Sales

Other Electric Utilities operating revenues for 2021 were $355 million USD (2020 – $354 million USD) and electric sales volumes were 1,262 GWh (2020 – 1,240 GWh).

BLPC

As at December 31, 2021, BLPC serves approximately 132,000 customers with $489 million USD of assets and a workforce of 412 employees. BLPC is regulated by the FTC, Barbados.

BLPC’s approved regulated return on rate base is 10 per cent. BLPC has a fuel pass-through mechanism which provides the opportunity to recover all prudently incurred fuel costs in a timely manner. The FTC approves the calculation of the fuel charge, which is adjusted on a monthly basis.

BLPC owns 266 MW of generating capacity, of which 96 per cent is oil-fired and 4 per cent is solar. The utility has an additional 12 MW of capacity from rental units. BLPC’s transmission system consists of 188 km of transmission lines, including major substations connected to the transmission and distribution system. The distribution system consists of 3,800 km of distribution lines which includes distribution supply substations.

GBPC

As at December 31, 2021, GBPC serves approximately 19,000 customers, with $349 million USD of assets and a workforce of 203 employees.

GBPC is regulated by the GBPA. The GBPA has granted GBPC a licensed, regulated and exclusive franchise to produce, transmit and distribute electricity on the island until 2054. Rates are set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on rate base. There is a fuel pass-through mechanism, which provides the opportunity to recover all prudently incurred fuel costs from customers in a timely manner and tariff review policy with new rates submitted every three years. GBPC’s approved regulated return on rate base was 8.37 per cent for 2021 (2020 - 8.34 per cent).

GBPC maintains insurance for its generation facilities. As with most utilities, its transmission and distribution networks are not covered by commercial insurance. In 2019, Hurricane Dorian restoration costs for GBPC’s transmission and distribution network assets were $15 million USD. In January 2020, the GBPA approved the deferral of these costs through a regulated asset with recovery through rates over a five-year period. Recovery of the asset began January 1, 2021.

As a result of Hurricane Matthew in 2016, a regulatory asset was established to recover associated restoration costs. In 2017, as part of the recovery of costs incurred as a result of Hurricane Matthew, the GBPA approved a fixed per kWh fuel charge and allowed the difference between this and the actual cost of fuel to be applied to the Hurricane Matthew regulatory asset. In September 2021, GBPC filed an application for rate review with the GBPA. As part of its decision issued January 14, 2022 and effective April 1, 2022, the GBPA approved the continued amortization of the remaining hurricane related regulatory asset over the three year period ending December 31, 2024.

Emera Incorporated – 2021 Annual Information Form	17

GBPC owns 98 MW of oil-fired generation, approximately 90 kilometres of transmission facilities and 670 kilometers of distribution facilities.

Domlec

As at December 31, 2021, Domlec serves approximately 35,700 customers, has a workforce of 210 employees and is regulated by the IRCD. The ordinary shares of Domlec are listed on the Eastern Caribbean Securities Exchange. On October 7, 2013, the IRCD issued a Transmission, Distribution & Supply License and a Generation License to Domlec, both of which came into effect on January 1, 2014 for a period of 25 years. Domlec’s approved regulated return on rate base is 15 per cent for 2021 and 2020. Substantially all of Domlec fuel costs flow through a fuel pass-through mechanism which provides opportunity to recover prudently incurred fuel costs from customers in a timely manner.

Domlec owns 26.7 MW of generating capacity of which 75 per cent is oil-fired and 25 per cent is hydro. Domlec owns 475 kilometres of transmission facilities and 709 kilometres of distribution facilities.

System Operation

BLPC, GBPC and Domlec have system control centres that co-ordinate and control their electric generation and transmission facilities with the goal of providing a reliable and secure electricity supply while maintaining economy of operations. The generation and transmission system control centres are linked to their generating stations and other key parts of their systems by the “Supervisory Control and Data Acquisition” systems, with fibre optic, voice and data communications networks.

Transmission and Distribution

BLPC, GBPC and Domlec transmit and distribute electricity from their generating stations to their customers.

Contribution to Consolidated Net Income and Adjusted NetIncome

Other Electric Utilities’ contribution to consolidated net income was $17 million USD in 2021 (2020 – $26 million USD). Other Electric Utilities’ contribution to consolidated adjusted net income was $16 million USD in 2021 (2020 – $24 million USD). For a reconciliation of Other Electric Utilities adjusted net income to consolidated net income, refer to the “Non-GAAP Financial Measures” and “Financial Highlights – Other Electric Utilities” sections of Emera’s MD&A, which is incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

SeasonalNature

Electricity sales and related generation varies significantly over the year in the Caribbean; Q3 is typically the strongest period, reflecting warmer weather. Dominica and Grand Bahama are also particularly prone to tropical storm and hurricane impacts during Q3.

Capital Investment

Other Electric Utilities capital investments (including AFUDC) for 2021 were $88 million USD (2020 – $111 million USD). In 2022, capital investment is expected to be approximately $100 million USD primarily in more efficient and cleaner sources of generation, including renewables and battery storage.

Environmental Considerations

Emera’s Caribbean utilities have implemented formal health & safety and environmental and management systems to assist in safeguarding the health and safety of its employees, contractors and customers while ensuring protection of the environment.

Emera Incorporated – 2021 Annual Information Form	18

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 a 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.

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 to customers.

PGS is regulated by the FPSC. NMGC is regulated by the NMPRC. Rates are set at a level that allow the utilities to collect total revenues equal to their cost to provide service, including an appropriate return on invested capital.

Market and sales

PGS, NMGC and SeaCoast Revenue and Sales by CustomerClass
	Gas Revenues (%)		Therms Gas Sales Volumes (%)
For the year ended December 31	2021	2020	2021	2020
Residential	53.1	50.6	14.6	13.2
Commercial	31.4	28.2	28.8	25.1
Industrial	5.5	5.6	51.7	51.9
Other	10.0	15.6	4.9	9.8
Total	100.0	100.0	100.0	100.0

PGS

As at December 31, 2021, PGS serves approximately 445,000 customers with $2.2 billion USD in assets and 681 employees. The PGS system includes approximately 23,150 kilometres of natural gas mains and 13,100 kilometres of service lines. Natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) was 1.9 billion therms in 2021.

As of 2021, the approved ROE range for PGS was 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 recovered through cost recovery clauses.

Fuel Recovery Clause

PGS recovers the costs it pays for gas supply and interstate transportation for system supply through its PGAC. This clause is designed to recover actual costs incurred by PGS for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, transportation, distribution, and sale of natural gas to its customers. These charges may be adjusted monthly subject to a cap approved annually by the FPSC.

Other Cost Recovery Clauses

The FPSC annually approves cost-recovery rates for conservation costs, including a return on capital invested, incurred in developing and implementing energy conservation programs. PGS has a Cast Iron/Bare Steel Pipe Replacement clause to recover the cost of accelerating the replacement of cast iron and bare steel distribution lines in the PGS system. In February 2017, the FPSC approved expansion of the Cast Iron/Bare Steel clause to allow recovery of accelerated replacement of certain obsolete plastic pipe.

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PGS estimates that the majority of cast iron and bare steel pipe will be removed from its system by the end of 2022, with replacement of obsolete plastic pipe continuing until 2028 under the rider.

NMGC

As at December 31, 2021, NMGC serves approximately 542,000 customers with $1.7 billion USD in assets and 698 employees. NMGC’s system includes 2,424 km of transmission lines and 17,593 km of distribution lines. Annual natural gas throughput was 839 million therms in 2021.

As of 2021, the approved ROE for NMGC is 9.375 per cent on an allowed equity capital structure of 52 per cent.

Fuel Recovery Clause

NMGC recovers gas supply costs through a PGAC. This clause recovers NMGC’s actual costs for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, distribution, and sale of natural gas to its customers.

On a monthly basis, NMGC can adjust charges based on the next month’s expected cost of gas and any prior month under-recovery or over-recovery. The NMPRC requires that NMGC annually file a reconciliation of the PGAC period costs and recoveries. NMGC must file a PGAC Continuation Filing with the NMPRC every four years to establish that continued use of the PGAC is reasonable and necessary. In December 2020, NMGC received approval of its PGAC Continuation Filing for the four-year period ending December 2024.

NMGCWinter Event Gas Cost Recovery

In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in an incremental $108 million for gas costs above what NMGC would normally have paid during this period. On June 15, 2021, the NMPRC approved the recovery over a period of 30 months beginning July 1, 2021. For more information, refer to the “Business Overview and Outlook – Gas Utilities and Infrastructure” section of Emera’s MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

WeatherNormalization Mechanism

In July 2019, the NMPRC approved changes to the company’s rate design to include a Weather Normalization Mechanism. This clause is designed to lower the variability of weather impacts during the annual October through April heating season. The Weather Normalization Mechanism will allow customer rates and company revenue to be more predictable by partially removing the impact of warmer than usual or colder than usual weather. Weather-related revenue increases or decreases experienced from October to April are adjusted annually in October of the following heating season.

IMP Regulatory Asset

A portion of NMGC’s annual spend on infrastructure is for integrity management programs (“IMP”), or the replacement and update of legacy systems. These programs are driven both by NMGC integrity management plans and federal and state mandates. In December 2020, NMGC received approval through its rate case to defer costs through an IMP regulatory asset for certain of its IMP capital investments occurring between January 1, 2022 and December 31, 2023 and is seeking recovery of the regulatory asset in its rate case filed on December 13, 2021.

SeaCoast

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SeaCoast will operate a 21-mile, 30-inch pipeline lateral that will be treated as a sales-type lease for accounting purposes. The lease of the pipeline lateral to Seminole will commence in 2022. The capital investment is approximately $100 million USD, with the majority of the project investment completed through 2021.

EBPC

EBPC owns Brunswick Pipeline, a regulated 145-km pipeline delivering re-gasified liquefied natural gas from the Canaport LNG import terminal near Saint John, New Brunswick to markets in the Northeastern United States. The pipeline travels through southwest New Brunswick and connects with M&NP at the Canada/U.S. border near Baileyville, Maine.

Since its commissioning in July 2009, the pipeline has been used solely to transport natural gas for RECL under a 25-year firm service agreement, which expires in 2034. Brunswick Pipeline is regulated by the CER, which has classified it as a Group II pipeline. As a regulated Group II pipeline, the tolls of Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to a regulatory approval process. 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 with RECL, as noted above. The firm service agreement provides for a predetermined toll increase in the fifth and fifteenth year of the contract.

M&NP

Emera owns a 12.9 per cent interest in M&NP, which is a 1,400 km pipeline that transports natural gas throughout markets in Atlantic Canada and the Northeastern United States.

Contribution to Consolidated Net Income

Gas Utilities and Infrastructure’s contribution to consolidated net income was $157 million USD in 2021 (2020 –$122 million USD).

Seasonal Nature

Gas sales volumes are primarily driven by general economic conditions, population and weather. Residential and commercial gas sales are seasonal. In Florida and New Mexico, Q1 is the strongest period for gas sales due to colder weather and heating demand.

Capital Investment

Capital investments (including AFUDC) in the Gas Utilities and Infrastructure segment in 2021 were $407 million USD (2020 - $553 million USD). In 2022, capital investment is expected to be approximately $445 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.

Environmental Considerations

Brunswick Pipeline is subject to both federal and provincial environmental regulations. Brunswick Pipeline has comprehensive integrity, safety and environmental programs in place, including an integrated management system to ensure compliance and continuous improvement of its integrity, safety and environmental programs. Brunswick Pipeline also conducts regularly scheduled physical inspections of the pipeline and its right-of-way.

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Economic Dependence

Brunswick Pipeline has a 25-year firm service agreement with RECL, which runs to 2034. The risk of non-payment is mitigated as Repsol, the parent company of RECL, has provided EBPC with a guarantee for all RECL’s payment obligations under the firm service agreement.

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 ETL. Emera Energy consists of EES, a wholly owned physical energy marketing and trading business and an equity investment in a 50.0 per cent joint venture ownership of Bear Swamp, a 633 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 US. It also includes costs associated with corporate activities that are not directly allocated to the operations of Emera’s subsidiaries and investments.

Emera Energy

EES derives revenue and earnings from the wholesale marketing and trading of natural gas, electricity and other energy-related commodities and derivatives within the company’s risk tolerances, including those related to value-at-risk and credit exposure. EES purchases and sells physical natural gas and electricity, the related transportation and transmission capacity rights, and provides related 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, US 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.

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

Contribution toConsolidated Net Income and Adjusted Net Income

Other’s contribution to consolidated net income was a loss of $412 million in 2021, compared to a gain of $19 million in 2020. Adjusted for after-tax mark-to-market, gain on the sale of Emera Maine, and impairment charges recognized on certain other assets, Other’s contribution to consolidated net income was a loss of $198 million compared to a loss of $252 million during the same period in 2020. For further information on the non-GAAP measure adjusted net income, refer to the “Non-GAAP Financial Measures” and “Financial Highlights – Other” sections of the MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

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Capital Investment

Capital investments in the Other segment were $1 million in 2021 (2020 – $3 million). In 2022, capital investment in the Other segment is expected to be $2 million.

GENERAL DEVELOPMENT OF THE BUSINESS

Three Year History and Changes Expected in 2022

The following discussion summarizes key developments in Emera’s business and operations over the last three completed financial years and changes that are expected to occur during the current financial year.

COVID-19 Pandemic

The Company’s priorities continue to be the reliable delivery of essential energy services to meet customers’ demands while maintaining the health and safety of its customers and employees and supporting the communities in which Emera operates. For more information on the COVID-19 Pandemic, refer to the “Introduction – COVID-19 Pandemic” section above.

Florida Electric Utility

Base Rate Adjustments– Approval of Settlement Agreement

Fuel and CapacityCharges

On January 19, 2022, Tampa Electric requested a mid-course adjustment to its fuel and capacity charges to recover an additional $169 million USD, effective with April 2022 customer bills, due to an increase in fuel commodity and capacity costs. The FPSC is expected to issue its decision in March 2022.

On July 19, 2021, Tampa Electric requested a mid-course adjustment of $83 million USD to its fuel and capacity charges, effective with September 2021 customer bills, due to an increase in fuel commodity and capacity costs in 2021. On August 3, 2021, the FPSC approved the request to recover the costs during the months of September through December 2021.

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Solar Projects

In September 2017, Tampa Electric announced its intention to invest approximately $850 million USD over four years in new utility-scale solar photovoltaic projects across its service territory. As of December 31, 2021, the full amount was invested and is recoverable through FPSC-approved SoBRAs. AFUDC was earned on these projects during construction. The FPSC has approved SoBRAs representing a total of 600 MW or $104 million USD annually in estimated revenue requirements for in-service projects.

The true-up filing for SoBRAs tranche 1 and 2 revenue requirement estimates which were included in base rates as of September 2018 and January 2019, respectively, was submitted on April 30, 2020, and the FPSC approved the amount on August 18, 2020. A $5 million USD true-up was returned to customers in 2020. The true-up filing for SoBRA tranche 3, included in base rates as of January 2020, was approved by the FPSC on October 12, 2021. An estimated $4 million USD true-up was returned to customers during 2021. The true-up for SoBRA tranche 4 will be filed in early 2022.

Big Bend Power Station Modernization

Tampa Electric expects to invest approximately $850 million USD during 2018 through 2023 to modernize the Big Bend Power Station, of which approximately $695 million USD has been invested through December 31, 2021. The modernization project will repower Big Bend Unit 1 with natural gas combined-cycle technology and eliminate coal as this unit’s fuel. As part of the modernization project, Tampa Electric retired the Unit 1 components that will not be used in the modernized plant in 2020 and Big Bend Unit 2 in 2021. Tampa Electric plans to retire Big Bend Unit 3 in 2023 as it is in the best interest of the customers from an economic, environmental risk and operational perspectives. For more information on the modernization of the Big Bend Power Station, refer to the “Regulatory Environments – Big Bend Modernization Project” section of Note 7, Regulatory Assets and Liabilities, to the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

StormProtection Cost Recovery Clause

On October 3, 2019, the FPSC issued a rule to implement a Storm Protection Plan (“SPP”) Cost Recovery Clause. This new clause provides a process for Florida investor-owned utilities, including Tampa Electric, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. Tampa Electric’s current approved SPP applies for the years 2020, 2021 and 2022, and Tampa Electric will file a new plan in 2022 to determine cost recovery in 2023, 2024, and 2025. For more information on the SPP, refer to the “Regulatory Environments – Storm Protection Cost Recovery Clause and Settlement Agreement” section of Note 7, Regulatory Assets and Liabilities, to the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

Canadian Electric Utilities

NSPI

Environmental Legislation and Regulations

There have been several recent environmental developments at both the federal and provincial levels, as described further below. These developments are consistent with NSPI’s decarbonization strategy and will facilitate an accelerated transition to cleaner energy. NSPI is engaging with the federal and provincial governments, customers and stakeholders to work towards achieving these requirements, goals and targets with a focus on customer affordability.

On November 5, 2021, the Nova Scotia provincial government enacted Bill 57, “Environmental Goals and Climate Change Reduction Act,” which signals the provincial government’s intent to implement several climate change related goals and greenhouse gas reduction targets, many of which overlap with and replace provisions of pre-existing acts.

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The legislation also introduces a goal to phase out coal-fired electricity generation in Nova Scotia by 2030. Subsequent provincial regulations will be required to detail how these goals and targets will be achieved.

On August 5, 2021, the federal government issued an update to the Pan-Canadian Framework on Clean Growth and Climate Change under the “Greenhouse Gas Pollution Pricing Act”. This update (the “Federal Benchmark”) applies to the 2023 through 2030 period and puts in place the legal mechanism for increasing the carbon tax in Canada by $15 per tonne annually and reaching $170 per tonne by 2030. It also outlines the minimum compliance criteria for recognizing systems like the Nova Scotia Cap-and-Trade Program to be considered equivalent to the Federal Benchmark.

On July 9, 2021, the Nova Scotia provincial government amended the Renewable Electricity Regulations, mandating that 80 per cent of electric sales be generated from renewable sources by 2030.

On June 29, 2021, the federal government enacted Bill C-12 “Canadian Net-Zero Emissions Accountability Act” with the objective of attaining net-zero emissions by 2050.

General Rate Application

On January 27, 2022, NSPI filed a General Rate Application (“GRA”) with the UARB. The GRA proposes a rate stability plan for 2022 through 2024 which includes average base rate increases of 2.9 per cent per year and average fuel rate increases pursuant to the FAM of 0.8 per cent per year on August 1, 2022, January 1, 2023 and January 1, 2024. The proposed rates would result in annualized incremental revenue (base and fuel rates) increases of $52 million in 2022 ($21 million related to August 1, 2022 through December 31, 2022), $54 million in 2023 and $56 million in 2024. A decision by the UARB is expected later this year.

Regulatory Matters - General

The Electricity Plan Act was enacted by the Province in December 2015, with a goal of providing rate stability and predictability for customers for the 2017 through 2019 period. NSPI operated under a rate stability plan for the 2017 through 2019 period, which included an average overall annual rate increase of 1.5 per cent to recover fuel costs for each of the three years.

The Electricity Plan Act further directed that any non-fuel revenues in excess of NSPI’s approved range of return in 2017 through 2019 were to be applied to the FAM. In addition, the financial benefit resulting from a change in the recognition of tax benefits for the South Canoe Project and Sable Wind Project was to be reserved and applied to the FAM over the same period.

NSPI is currently operating under a three-year fuel stability plan which results in an average annual overall rate increase of 1.5 per cent to recover fuel costs for the period of 2020 through 2022. Differences between actual fuel costs and fuel revenues recovered from customers during 2020 to 2022 will be recovered or returned to customers after 2022, as required under NSPI’s fuel stability plan. The UARB’s decision to approve NSPI’s fuel stability plan directed that annual non-fuel revenues above NSPI’s approved range of ROE are to be applied to the FAM.

Pursuant to the FAM Plan of Administration, NSPI’s Fuel Costs are subject to independent audit every two years. On April 6, 2021, the UARB’s decision on the FAM audit findings and recommendations relating to fiscal 2018 and 2019 was publicly released. The final recommendations were endorsed by the UARB and included two disallowances. The impacts of the disallowances were not material to NSPI’s financial results.

Regulatory Matters – Maritime Link

The Maritime Link entered service on January 15, 2018 and NSPI started interim assessment payments to NSPML at that time. The UARB approved 2021 interim cost assessment recovery payment to NSPML was $172 million (2020 - $145 million) and as of December 31, 2021 $139 million (2020 - $135 million) has been paid.

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The approved interim cost assessment payments are subject to a holdback of $10 million pending UARB agreement that benefits from the Maritime Link are realized for NSPI customers. For 2021, NSPI has recorded a $10 million (2020 - $4 million) holdback payable to NSPML and NSPML has deferred collection of $23 million in depreciation expense in 2021.

For more information, refer to the “Regulatory Assets and Liabilities – Regulatory Environments – Canadian Electric Utilities – NSPI” section of Emera’s Audited Financial Statements, which are incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

ENL

Maritime Link Project

The Maritime Link entered service on January 15, 2018 and provides for the transmission of energy as well as improved reliability and ancillary benefits, supporting the efficiency and reliability of both provinces. The Maritime Link will transmit at greater capacity when the Lower Churchill projects (including Muskrat Falls and LIL) are complete, which is anticipated to take place in 2022.

Delivery of NS Block

Other Electric Utilities

Sale of Emera Maine

On March 24, 2020, Emera completed the sale of Emera Maine for a total enterprise value of $2.0 billion ($1.4 billion USD). A gain on sale of $585 million ($309 million after tax, or $1.26 per common share), net of transaction costs, was recognized in “Other Income” on the Consolidated Statements of Income. For further detail, refer to the “Significant Items Affecting Earnings” and “Financial Highlights – Other” sections in Emera’s MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

ECI

BLPC General Rate Review

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For more information on BLPC’s general rate review application, refer to the “Business Overview and Outlook - Other Electric Utilities Outlook” section in Emera’s MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

BLPC LicenseNegotiations

BLPC is regulated by the Fair Trading Commission (“FTC”), an independent regulator, under the Utilities Regulation (Procedural) Rules 2003. The Government of Barbados has granted BLPC a franchise to generate, transmit and distribute electricity on the island until 2028. In 2019, the Government of Barbados passed legislation amending the number of licenses required for the supply of electricity from a single integrated license which currently exists to multiple licenses for Generation, Transmission and Distribution, Storage, Dispatch and Sales. In March 2021, BLPC reached commercial agreement with the Government of Barbados for each of the license types, subject to the passage of implementing legislation. Following a general election called late in 2021 for January 19, 2022, the new licenses are expected to take effect in 2022 on completion of the legislative process. The Dispatch license will have 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 currently assessing the full impact of the new licenses on its business and working towards the successful implementation of the licenses.

For more information, refer to the “Regulatory Assets and Liabilities – Regulatory Environments – Other Electric Utilities – The Barbados Light & Power Company Limited” section of Emera’s Audited Financial Statements, which are incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

BLPC Fuel Hedging

On October 21, 2021 the FTC approved BLPC’s application to implement a fuel hedging program which will be incorporated into the calculation of the fuel clause adjustment. On November 10, 2021 BLPC requested the FTC review the required 50/50 cost sharing arrangement between BLPC and customers in relation to the hedging administrative costs, or any gains and losses associated with the hedging program. A decision is expected from the FTC in the first half of 2022

GBPC Application for Rate Review

On January 14, 2022, the GBPA issued its decision on GBPC’s application for rate review that was filed with the GBPA on September 23, 2021. The decision, which becomes effective April 1, 2022, allows for an increase in revenues of $3.5 million USD annually. The new rates include a regulatory ROE of 12.84 per cent.

In 2017, as part of the recovery of costs incurred as a result of Hurricane Matthew, the GBPA approved a fixed per kWh fuel charge and allowed the difference between this and the actual cost of fuel to be applied to the Hurricane Matthew regulatory asset. In September 2021, GBPC filed an application for rate review with the GBPA. As part of its decision issued January 14, 2022 and effective April 1, 2022, the GBPA approved the continued amortization of the remaining regulatory asset over the three year period ending December 31, 2024.

Gas Utilities and Infrastructure

PGS

Settlement Agreement

On November 19, 2020, the FPSC approved a settlement agreement filed by PGS. The settlement agreement allows for an increase to base rates by $58 million USD annually effective January 1, 2021, which is a $34 million USD increase in revenue and $24 million USD increase of revenues previously recovered through the cast iron and bare steel replacement rider.

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It provides PGS the ability to reverse a total of $34 million USD of accumulated depreciation through 2023 and sets new depreciation rates effective January 1, 2021. Under the agreement base rates are frozen from January 1, 2021 to December 31, 2023, unless its earned ROE were to fall below 8.9 per cent before that time with an allowed equity in the capital structure of 54.7 per cent from investor sources of capital. The settlement agreement provides for the deferral of income taxes as a result of changes in tax laws. The changes would be reflected as a regulatory asset or liability and either result in an increase or a decrease in customer rates through a subsequent regulatory process.

NMGC

Settlement Agreement

On December 16, 2020, the NMPRC approved a settlement agreement for new rates that became effective on January 1, 2021. The new rates reflect the recovery of capital investment in pipelines and related infrastructure and resulted in an increase in revenue of approximately $5 million USD annually.

NMGC Winter Event Gas Cost Recovery

In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in an incremental $108 million USD for gas costs above what it would normally have paid during this period. NMGC normally recovers gas supply and related costs through a purchased gas adjustment clause. On April 16, 2021, NMGC filed a Motion for Extraordinary Relief, as permitted by the NMPRC rules, to extend the terms of the repayment of the incremental gas costs and to recover a carrying charge. On June 15, 2021, the NMPRC approved the recovery of $108 million USD and related borrowing costs over a period of 30 months beginning July 1, 2021.

Rate Case

On December 13, 2021, NMGC filed a rate case with the NMPRC for new rates to become effective January 1, 2023. NMGC requested a $41 million increase in annual base revenues primarily as a result of increased operating costs and capital investments in pipelines and related infrastructure. A decision from the NMPRC is expected by the end of 2022.

Other

Sale of Emera Energy’s New England Gas Generating Facilities and Bayside Facility

On March 29, 2019, Emera completed the sale of its three NEGG Facilities for cash proceeds of $799 million ($598 million USD), including working capital adjustments. On March 5, 2019, the Company sold its Bayside facility for cash proceeds of $46 million. An immaterial loss was recognized on these dispositions. Proceeds from the sales were used to reduce corporate debt and support capital investment opportunities within Emera’s regulated utilities.

Removal of Legislative Restriction on Non-Canadian Resident Ownership

On April 12, 2019, amendments to the Privatization Act and the Reorganization Act were enacted, removing the legislative restriction preventing non-Canadian residents from holding more than 25 per cent of Emera’s voting shares, in aggregate. On July 11, 2019, shareholders passed a special resolution to amend the Company’s articles of association to remove this restriction.

USGAAP – Exemptive Relief and Companies Act Relief

On January 26, 2018, Emera was granted the Exemptive Relief by Canadian securities regulators allowing Emera to continue to report its financial results in accordance with USGAAP. On July 18, 2018, Emera was granted the Companies Act Relief allowing Emera to continue to be exempt from the requirement to prepare its annual financial statements in accordance with IFRS.

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Both the Exemptive Relief and the Companies Act Relief will remain in effect until the earlier of: (i) January 1, 2024; (ii) the first day of the Company’s financial year commencing after the Company ceases to have activities subject to rate regulation; and (iii) the effective date prescribed by the International Accounting Standards Board for the mandatory application of a standard within IFRS specific to entities with rate-regulated activities. The Exemptive Relief and the Companies Act Relief each replace similar exemptive relief that had been previously granted to Emera in 2014 and that would have expired by January 1, 2019.

On January 28, 2021, the IASB published an Exposure Draft: Regulatory Assets and Regulatory Liabilities, which proposes the accounting model under which a company subject to rate regulation that meets the scope criteria would recognize regulatory assets and liabilities. The proposed effective date is annual reporting periods beginning on or after a date 18-24 months from the date of publication of the standard. The Company will continue to monitor the development of the standard and assess the impact on the existing Exemptive Relief and Companies Act Relief.

Financing Activity

At-The-Market Equity Program

During 2019, approximately 1.8 million common shares were issued under the ATM Program at an average price of $56.56 per share for gross proceeds of $100 million ($98.7 million net of issuance costs). As at December 31, 2019, an aggregate gross sales limit of $500 million remained available for issuance under the ATM program.

During 2020, approximately 4.5 million common shares were issued under the ATM program at an average price of $56.04 per share for gross proceeds of $255 million ($251 million net of issuance costs). As at December 31, 2020, an aggregate gross sales limit of $245 million remained available for issuance under the ATM Program.

During 2021, approximately 4.99 million common shares were issued under the ATM Program at an average price of $57.63 per share for gross proceeds of $287 million ($284 million net of issuance costs). As at December 31, 2021, an aggregate gross sales limit of $457 million remained available for issuance under the ATM program.

During 2022, up to and including February 11, 2022, no common shares were issued under the ATM Program and an aggregate gross sales limit of $457 million remains available for issuance under the ATM program.

Preferred Share Issuances

On January 7, 2020, Emera announced it would not redeem the 8,000,000 Series F First Preferred Shares. The holders of the Series F First Preferred Shares had the right, at their option, to convert all or any of their Series F First Preferred Shares, on a one-for-one basis, into Series G First Preferred Shares on February 15, 2020 or to continue to hold their Series F First Preferred Shares. On February 6, 2020, Emera announced that, after having taken into account all conversion notices received from holders, no Series F First Preferred Shares would be converted into Series G First Preferred Shares.

On July 9, 2020, Emera announced it would not redeem Series A First Preferred Shares or the Series B First Preferred Shares. On August 17, 2020, Emera announced 128,610 of its 3,864,636 issued and outstanding Series A First Preferred Shares were tendered for conversion into Series B First Preferred Shares and 1,130,788 of its 2,135,364 issued and outstanding Series B First Preferred Shares were tendered for conversion into Series A First Preferred Shares, all on a one-for-one basis.

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As a result of the conversion, Emera has 4,866,814 Series A First Preferred Shares and 1,133,186 Series B First Preferred Shares issued and outstanding.

On April 6, 2021, Emera issued 8 million Series J First Preferred Shares at $25.00 per share at an initial dividend rate of 4.25 per cent. The aggregate gross and net proceeds from the offering were $200 million and $196 million, respectively. The net proceeds of the preferred share offering were used for general corporate purposes.

On September 24, 2021, Emera issued 9 million Series L First Preferred Shares, at $25.00 per share at an annual yield of 4.60 per cent. The aggregate gross and net proceeds from the offering were $225 million and $222 million, respectively. The net proceeds of the preferred share offering were used for general corporate purposes.

Senior Notes

On June 4, 2021, Emera US Finance LP completed an issuance of $750 million USD senior notes. The issuance included $450 million USD senior notes that bear interest at a rate of 2.64 per cent with a maturity date of June 15, 2031 and $300 million USD senior notes that bear interest at a rate of 0.83 per cent with a maturity date of June 15, 2024. The USD senior notes are guaranteed by Emera and Emera US Holdings Inc., a wholly owned Emera subsidiary.

From the $750 million USD senior notes issuance discussed above, on June 15, 2021, Emera US Finance LP repaid its previously outstanding $750 million USD senior notes on maturity.

For more information on financing activities for Emera and its subsidiaries, please refer to the “Liquidity and Capital Resources” section of Emera’s MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

RISK FACTORS

For Emera’s risk factors, refer to the “Enterprise Risk and Risk Management” section of the MD&A and the “Principal Financial Risks and Uncertainties” section of note 27, Commitments and Contingencies, to the Audited Financial Statements, which are each incorporated herein by reference, copies of which are available electronically under Emera’s profile on SEDAR at www.sedar.com.

CAPITAL STRUCTURE

The authorized capital of Emera consists of an unlimited number of common shares, an unlimited number of first preferred shares and an unlimited number of second preferred shares. Each class of preferred shares is issuable in series.

As at December 31, 2021, 261,065,175 common shares, 4,866,814 Series A First Preferred Shares, 1,133,186 Series B First Preferred Shares, 10,000,000 Series C First Preferred Shares, 5,000,000 Series E First Preferred Shares, 8,000,000 Series F First Preferred Shares, 12,000,000 Series H First Preferred Shares, 8,000,000 Series J First Preferred Shares, 9,000,000 Series L First Preferred Shares, 2,200,525 Barbados DRs and 1,814,135 Bahamas DRs were issued and outstanding.

Common Shares

The holders of common shares are entitled to receive notice of and to attend all annual and special meetings of the shareholders of Emera, other than separate meetings of holders of any other class or series of shares, and to one vote in respect of each common share held at such meetings.

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The holders of common shares are entitled to dividends on a pro rata basis, as and when declared by the Board. Subject to the rights of the holders of the first preferred shares and second preferred shares, if any, who are entitled to receive dividends in priority to the holders of the common shares, the Board may declare dividends on the common shares to the exclusion of any other class of shares of Emera.

On the liquidation, dissolution or winding-up of Emera, holders of common shares are entitled to participate rateably in any distribution of assets of Emera, subject to the rights of holders of first preferred shares and second preferred shares, if any, who are entitled to receive the assets of the Company on such a distribution in priority to the holders of the common shares.

There are no pre-emptive, redemption, purchase or conversion rights attaching to the common shares. The foregoing description is subject to the “Share Ownership Restrictions” section below.

Emera First Preferred Shares

The first preferred shares of each series rank on parity with the first preferred shares of every other series and are entitled to a preference over the second preferred shares, the common shares, and any other shares ranking junior to the first preferred shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of the Company in the liquidation, dissolution or wind-up, whether voluntary or involuntary.

In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the first preferred shares, the holders of the first preferred shares will be entitled, for only as long as the dividends remain in arrears, to attend any meeting of shareholders of the Company at which directors are to be elected and to vote for the election of two directors out of the total number of directors elected at any such meeting.

The first preferred shares of each series are not redeemable at the option of their holders. For a summary of the terms and conditions of the Company’s authorized First Preferred Shares as of December 31, 2021, refer to Appendix “B” of this AIF.

Emera Second Preferred Shares

The second preferred shares have special rights, privileges, restrictions and conditions substantially similar to the first preferred shares, except that the second preferred shares rank junior to the first preferred shares with respect to the payment of dividends, repayment of capital and the distribution of assets of Emera in the event of liquidation, dissolution or winding-up of Emera. As at December 31, 2021, Emera had not issued any second preferred shares.

Share Ownership Restrictions

As required by the Reorganization Act and pursuant to the Privatization Act, the Articles of Emera provide that no person, together with associates thereof, may subscribe for, have transferred to that person, hold, beneficially own or control, directly or indirectly, otherwise than by way of security only, or vote, in the aggregate, voting shares of Emera to which are attached more than 15 per cent of the votes attached to all outstanding voting shares of Emera.

The common shares, and in certain circumstances the Series A First Preferred Shares, Series B First Preferred Shares, Series C First Preferred Shares, Series E First Preferred Shares, Series F First Preferred Shares, Series H First Preferred Shares, Series J First Preferred Shares and Series L First Preferred Shares are considered to be voting shares for purposes of the constraints on share ownership.

Emera’s Articles contain provisions for the enforcement of these constraints on share ownership including provisions for suspension of voting rights, forfeiture of dividends, prohibitions of share transfer and issuance, compulsory sale of shares and redemption, and suspension of other shareholder rights. The Board may require shareholders to furnish statutory declarations as to matters relevant to enforcement of the restrictions.

Emera Incorporated – 2021 Annual Information Form	31

CREDIT RATINGS

Emera has the following credit ratings^(1)^ by the Rating Agencies:

	Moody’s	S&P	Fitch
Corporate	Baa3	BBB	BBB
Outlook	Stable	Stable	Stable
Senior unsecured debt program	Baa3	BBB-	BBB
Hybrid Notes	Ba2	BB+	BB+
First Preferred Shares	N/A	P-3 (high)	N/A
(1)	Ratings are intended to provide investors with an independent measure of the credit quality of an issue of securities<br>and are indicators of the likelihood of the payment capacity and willingness of an issuer to meet its financial commitment in accordance with the terms of the obligation. The credit ratings assigned by the Rating Agencies are not recommendations to<br>buy, sell, or hold securities in as much as such ratings are not a comment upon the market price of the securities or their stability for a particular investor. The credit ratings assigned to the securities may not reflect the potential impact of<br>all risks on the value of the securities. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a Rating Agency in the future if in its judgment<br>circumstances so warrant.
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Moody’s

Moody’s credit ratings are on a long-term debt rating scale that ranges from Aaa to C, representing the range from highest to lowest quality of such rated securities. The rating of Baa3 obtained from Moody’s in respect of the senior unsecured debt is the fourth highest of nine available rating categories and indicates that the obligations are subject to moderate credit risk. As such, they are considered medium-grade and may possess speculative characteristics. The rating of Ba2 from Moody’s in respect of the Hybrid Notes is characterized as having speculative elements and being subject to substantial credit risk. It is the fifth highest of nine available rating categories. Moody’s appends numerical modifiers 1, 2 and 3 to each generic rating classification from Aa through Caa. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and the modifier 3 indicates a ranking in the lower end of that generic rating category.

S&P

S&P’s credit ratings are on a long-term debt scale that ranges from AAA to D, representing the range from highest to lowest quality of such rated securities. The issuer rating of BBB obtained from S&P in respect of the corporate rating indicates that the issuer has adequate capacity to meet its financial commitments. The issue rating of BBB- from S&P in respect of the senior unsecured debt indicates that the obligations exhibit adequate protection parameters. The issue rating of BB+ from S&P in respect of the Hybrid Notes indicates that the obligations exhibit adequate projection parameters in the near term however the obligor may not have the capacity to meet its obligations in the long term. The issue and issuer ratings of BBB and BB are the fourth and fifth highest, respectively, of ten available ratings categories and the addition of either a “(+)” or a “(-)” designation after a rating indicates the relative standing within a particular category. In each case, however, adverse economic conditions or changing circumstances are more likely to lead to weakened capacity of the obligor to meet its financial commitments on the obligation.

A P-3 (high) rating with respect to Emera’s issued and outstanding First Preferred Shares is the third highest of the eight standard categories of ratings utilized by S&P for preferred shares.

Fitch

Fitch’s credit ratings are on a long-term debt scale that ranges from AAA to D, representing the range from highest to lowest quality of such rated securities. The rating of BBB obtained from Fitch in respect of the senior unsecured debt is the fourth highest of nine available rating categories and indicates that the issuer has adequate capacity to meet its financial commitments.

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The rating of BB from Fitch in respect of the Hybrid Notes is characterized as having elevated default risk however business or financial flexibility exists that support servicing the financial commitments. The BB rating from Fitch is the fifth highest of nine available ratings categories and the addition of either a “(+)” or a “(-)” designation after a rating indicates the relative standing within a particular category. In each case, however, adverse economic conditions or changing circumstances are more likely to lead to weakened capacity of the obligor to meet its financial commitments on the obligation.

Emera has made, or will make, payments in the ordinary course to the Rating Agencies in connection with the assignment of ratings on both Emera and its securities. In addition, Emera has made customary payments in respect of certain subscription services provided to Emera by the Rating Agencies during the last two years.

Emera Incorporated – 2021 Annual Information Form	33

DIVIDENDS

Any dividend payments will be at the Board’s discretion based upon earnings and capital requirements and any other factors as the Board may consider relevant. On September 24, 2021 Emera extended its annual dividend growth rate target of four to five per cent through 2024. The Company targets a long-term dividend payout ratio 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 maintains the Dividend Reinvestment Plan, which provides an opportunity for shareholders to reinvest dividends and to participate in optional cash contributions for the purpose of purchasing common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2021.

The Board approved the payment of the following dividends during the last three completed fiscal years, as summarized in the following table:

Class of Shares
Common Shares^(1)^, ^(2)^, ^(3)^	2.5750	2.4750	$2.3750
Series A First Preferred<br>Shares^(4)^	0.5456	0.6155	$0.6388
Series B First Preferred Shares	0.4873	0.6965	$0.8727
Series C First Preferred<br>Shares^(5)^	1.18024	1.18024	$1.18024
Series E First Preferred Shares	1.1250	1.1250	$1.1250
Series F First Preferred<br>Shares^(6)^	1.05052	1.053515	$1.0625
Series H First Preferred<br>Shares^(7)^	1.2250	1.2250	$1.2250
Series J First Preferred<br>Shares^(8)^	0.646965	-	-
Series L First Preferred<br>Shares^(9)^	0.1638	-	-

All values are in US Dollars.

(1)	On September 27, 2019, Emera approved an increase in the annual common share dividend rate from $2.35 to $2.45.<br>The first payment was effective November 15, 2019.
(2)	On September 16, 2020, Emera approved an increase in the annual common share dividend rate from $2.45 to $2.55.<br>The first payment was effective November 15, 2020.
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(3)	On September 24, 2021, Emera approved an increase in the annual common share dividend rate from $2.55 to $2.65.<br>The first payment was effective November 15, 2021.
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(4)	The Series A First Preferred Shares annual dividend rate was reset from $0.6388 to $0.5456 for the five year period<br>commencing August 15, 2020 and ending on (and inclusive of) August 14, 2025.
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(5)	The Series C First Preferred Shares annual dividend rate was reset from $1.0250 to $1.18024 for the five year period<br>commencing August 15, 2018 and ending on (and inclusive of) August 14, 2023.
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(6)	The Series F First Preferred Shares annual dividend rate was reset from $1.0625 to $1.0505 for the five year period<br>commencing February 15, 2020 and ending on (and inclusive of) February 14, 2025.
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(7)	The Series H First Preferred Shares with an annual dividend rate of $1.2250 (per share) were issued May 31, 2018.<br>
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(8)	The Series J First Preferred Shares with an annual dividend rate of $1.0625 (per share) were issued April 6, 2021.<br>
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(9)	The Series L First Preferred Shares with an annual dividend rate of $1.150 (per share) were issued September 24,<br>2021.
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Pursuant to the Income Tax Act (Canada) and corresponding provincial legislation, all dividends paid on Emera’s common shares and first preferred shares qualify as eligible dividends.

Emera Incorporated – 2021 Annual Information Form	34

MARKET FOR SECURITIES

Trading Price and Volume

Emera’s common shares, Series A First Preferred Shares, Series B First Preferred Shares, Series C First Preferred Shares, Series E First Preferred Shares, Series F First Preferred Shares, Series H First Preferred Shares, Series J First Preferred Shares and Series L First Preferred Shares are listed and posted for trading on the TSX under the symbols “EMA”, “EMA.PR.A”, “EMA.PR.B”, “EMA.PR.C”, “EMA.PR.E”, “EMA.PR.F”, “EMA.PR.H”, “EMA.PR.J” and “EMA.PR.L”, respectively. The Barbados DRs are listed on the BSE under the symbol EMABDR. The Bahamas DRs are listed on the BISX under the symbol EMAB. The trading volume and high and low price for Emera’s securities for each month of 2021 are set out In Appendix “C” of this AIF.

At-The-Market Equity Program

On August 12, 2021, Emera renewed its ATM Program that allows the Company to issue up to $600 million of common shares from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price. The ATM Program was renewed pursuant to a prospectus supplement to the Company’s short form base shelf prospectus dated August 5, 2021. The ATM program is expected to remain in effect until September 5, 2023. As at December 31, 2021, an aggregate gross sales limit of $457 million remains available for issuance under the ATM program. For more information on the ATM Program, refer to “General Development of the Business – Financing Activity – At-The-Market Equity Program” above.

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DIRECTORS AND OFFICERS

Directors

The following information is provided for each Director of Emera as at December 31, 2021^(1)^:

Name, Residence, Principal Occupations During the Past Five Years	Director<br><br><br>Since^(2)^	Committees^(3)^
M. Jacqueline Sheppard (Chair), Calgary, Alberta, Canada<br><br><br>Chair of the Board since May 2014. Director of Alberta Investment Management Corporation (AIMCo), an institutional investment<br>manager. Founder and former Lead Director of Black Swan Energy Inc., an Alberta upstream energy company, which was sold in July 2021. Director of ARC Resources Ltd., a publicly traded Canadian energy company. Former Executive Vice President,<br>Corporate and Legal of Talisman Energy Inc. Former Chair of the Research and Development Corporation of the Province of Newfoundland and Labrador, a provincial Crown Corporation. Former Director of Cairn Energy PLC, a publicly traded UK-based<br>international upstream company. Past Director of Emera’s subsidiary, Emera Newfoundland & Labrador Holdings Inc. from 2011 to May, 2016.	2009	(4)
Scott C. Balfour, Halifax, Nova Scotia, Canada<br><br><br>A Director and President and Chief Executive Officer of Emera since March 29, 2018. Mr. Balfour is a Director of many Emera<br>subsidiaries, including being Chair of Tampa Electric Company and Nova Scotia Power Inc. He is a former director of Martinrea International Inc. He was Chief Operating Officer from 2016 to 2018 and was Executive Vice President and Chief Financial<br>Officer of Emera from April 2012 to March 2016. From 1994 to 2011 he was Chief Financial Officer and then President of Aecon Group Inc., a Canadian publicly traded construction and infrastructure development company. He is also past Chair of the<br>Ontario Energy Association.	2018	(5)
James V, Bertram Calgary, Alberta, Canada<br><br><br>Chair of the Board, Keyera Corporation. Formerly President, and Chief Executive Officer of Keyera from its inception in 1998 until<br>2015, when he became Executive Chair. Previously Vice President – Marketing for the worldwide operations of Gulf Canada. Director of Methanex Corporation, the world’s largest producer and supplier of methanol to major international<br>markets.	2018	Chair of HSEC and Member of MRCC
Henry E. Demone, Lunenburg, Nova Scotia, Canada<br><br><br>Former Chair of High Liner Foods, the leading North American processor and marketer of value-added frozen seafood. Mr. Demone was<br>President of High Liner Foods since 1989 and its President and Chief Executive Officer from 1992 to May 2015. He was interim Chief Executive Officer of High Liner Foods from August 2017 until April 2018. A Director of Saputo Inc.	2014	Chair of MRCC and Member of<br><br><br>NCGC
Kent M. Harvey, New York, New York, U.S.<br><br><br>Former Chief Financial Officer for PG&E Corporation, an energy-based holding company, and the parent of Pacific Gas and Electric<br>Company, an energy company that serves 16 million Californians across a 70,000 square-mile service area in Northern and Central California.	2017	Chair of AC and Member of HSEC
B. Lynn Loewen, FCPA, FCA, Westmount, Quebec, Canada<br><br><br>Former President of Minogue Medical Inc., a healthcare organization which delivers innovative medical technologies to hospitals and<br>clinics. President of Expertech Network Installation Inc. from 2008 to 2011. Director of Xplornet Communications Inc., a Canadian broadband service provider.	2013	Member of AC, HSEC and RSC
Emera Incorporated – 2021 Annual Information Form	36
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John B. Ramil, Tampa, Florida, U.S.<br><br><br>Former President and Chief Executive Officer of TECO Energy. Held a variety of leadership positions in his four decades with Tampa<br>Electric. Former member of the board of the Edison Electric Institute, an industry association. Chair of GuideWell Mutual Holding Corporation and Blue Cross and Blue Shield of Florida boards. Member of the Florida Council of 100, the board of the<br>Moffitt Cancer Center Institute and Trustee and past Chair of the University of South Florida. Former member of the board of the Tampa Bay Partnership.	2016	Member of HSEC
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Andrea S. Rosen, Toronto, Ontario, Canada<br><br><br>Former Vice-Chair of TD Bank Financial Group and President of TD Canada Trust. Director of Manulife Financial Corporation, a Canadian<br>multinational insurance company and financial services provider; Ceridian HCM Holding Inc., a global human capital management software company and Element Fleet Management Corp., a global fleet management company, providing services and financing<br>for commercial vehicle fleets. Former Director of Alberta Investment Management Corporation. Former Director of Hiscox Ltd., a Bermuda-incorporated specialty insurer listed on the London Stock Exchange.	2007	Chair of NCGC and Member of AC
Richard P. Sergel, Boston, Massachusetts, U.S.<br><br><br>Former President and Chief Executive Officer of the North American Electric Reliability Corporation (NERC). Former President and<br>Chief Executive Officer of National Grid USA from 2000 to 2004. Also former President and Chief Executive Officer of the New England Electric System. Presently a Director of State Street Corporation. Has also served on the boards of the Edison<br>Electric Institute and the Consortium for Energy Efficiency.	2010	Member of AC and NCGC
Karen H. Sheriff, Toronto, Ontario, Canada<br><br><br>Ms. Sheriff is past President and CEO of Q9 Networks Inc., and prior to that, President and CEO of Bell Aliant, Inc., from 2008 to<br>2014. She held senior leadership positions for more than nine years with BCE Inc. and currently serves on the BCE Inc. Board of Directors. She spent over 10 years at United Airlines in the areas of marketing, strategy, human resources, and finance.<br>She is a former member of the Board of Directors of CPP Investments and WestJet Airlines Ltd.	2021	Member of MRCC and RSC
Jochen E. Tilk, Toronto, Ontario, Canada<br><br><br>Former Executive Chair of Nutrien Ltd., a Canadian global supplier of agricultural products and services based in Saskatoon,<br>Saskatchewan. Former President and Chief Executive Officer of Potash Corporation of Saskatchewan. Previously President and Chief Executive Officer of Inmet Mining Corporation, a Canadian-based, international metals company. Mr. Tilk is a director of<br>AngloGold Ashanti Limited, a publicly listed international gold mining company, headquartered in Johannesburg, South Africa. He is also a director of the Princess Margaret Cancer Foundation, a not-for-profit organization. He is the former Chair of<br>the board of directors of Canpotex Limited. Former Director of the Fertilizer Institute and the International Fertilizer Association.	2018	Chair of RSC and Member of MRCC and NCGC
(1)	Effective February 11, 2022, Paula Y. Gold-Williams and Ian E. Robertson joined the Emera Board of Directors.<br>
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(2)	Denotes the year the individual became a Director of Emera. Directors are elected for a one year term which expires at<br>the termination of Emera’s annual general meeting;
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(3)	Audit Committee (AC), Health, Safety and Environment Committee (HSEC), Management Resources and Compensation Committee<br>(MRCC), Nominating and Corporate Governance Committee (NCGC), and Risk and Sustainability Committee (RSC);
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(4)	Ms. Sheppard is not a member of any committee but attends all committee meetings as Chair of the Board;<br>
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(5)	Mr. Balfour is not a member of any committee as he is the President and Chief Executive Officer of the Company but<br>attends all committee meetings.
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Emera Incorporated – 2021 Annual Information Form	37
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Officers

The Officers of Emera as at December 31, 2021 were as follows:

Name and Residence	Principal Occupations During the Past Five Years
Scott C. Balfour<br> <br>President and Chief<br>Executive Officer<br> <br>Halifax, Nova Scotia, Canada	A Director and President and Chief Executive Officer of Emera since March 29, 2018.^(1)^
Gregory W. Blunden, FCPA, FCA<br><br><br>Chief Financial Officer<br> <br>Halifax, Nova Scotia, Canada	Chief Financial<br>Officer of Emera since March 2016.
Karen E. Hutt<br><br><br>Executive Vice-President, Business Development and Strategy<br> <br>Halifax, Nova Scotia,<br>Canada	Executive Vice-President, Business Development and Strategy of Emera since October 21, 2019. Previously, President and Chief<br>Executive Officer of NSPI since August 2016. From May 2015 to July 2016, Vice President, Mergers and Acquisitions at Emera. From August 2010 to April 2015, Executive Vice President, Commercial at Emera Energy (including appointment to President,<br>Northeast Wind in November 2012).
Richard C. Janega<br><br><br>Chief Operating Officer, Electric Utilities, Canada and Caribbean<br> <br>Halifax, Nova Scotia,<br>Canada	Chief Operating Officer, Electric Utilities, Canada, US Northeast, and Caribbean of Emera since March 31, 2018. Director of NSPI<br>since May 2018. Interim President and Chief Executive Officer of NSPI from June to October 2020. Director and President and CEO of NSPML. Former Chair of the Board of Emera Maine from March 2018 until March 2020. Chief Executive Officer of ENL since<br>2014. Chair and President of ECI and Chair of both GBPC and BLPC. Former Chief Operating Officer for NSPI.
Bruce A. Marchand<br><br><br>Chief Legal and Compliance Officer Halifax, Nova Scotia, Canada	Chief Compliance Officer of Emera since December 1, 2014. Chief Legal Officer of Emera since January 2012. Prior to January 2012,<br>Senior Partner at the law firm of McInnes Cooper.
R. Michael Roberts<br><br><br>Chief Human Resources Officer<br> <br>Halifax, Nova Scotia, Canada	Chief Human Resources Officer of Emera and NSPI since December 1, 2014. Previously, Vice President, Corporate Development at Irving<br>Shipbuilding and Vice President, Human Resources at Bell Aliant.
Daniel P. Muldoon<br><br><br>Executive Vice-President Project Development and Operations Support<br> <br>Halifax, Nova<br>Scotia, Canada	Executive Vice-President Project Development and Operations Support of Emera. Chair of the Boards of ENL, EBPC, Emera Technologies<br>LLC and NMGC. Former Director of Emera Maine from August 2013 until March 2020. Director of TEC and NSPML. Formerly Executive Vice-President, Major Renewables and Alternative Energy since May 2014.
Stephen D. Aftanas<br><br><br>Corporate Secretary<br> <br>Halifax, Nova Scotia, Canada	Corporate Secretary of Emera since September 2008. Corporate Secretary of NSPI from September 2008 to December 2019.

(1) Mr. Balfour’s principal occupations during the past five years are described above in the Directors table.

As at December 31, 2021, the Directors and Officers, in total, beneficially owned or controlled, directly or indirectly, 159,531 common shares or less than 1 per cent of the issued and outstanding shares of Emera.

Emera Incorporated – 2021 Annual Information Form	38

AUDIT COMMITTEE

The Audit Committee of Emera is composed of the following four members, all of whom are independent Directors: Kent M. Harvey (Chair), B. Lynn Loewen, Andrea S. Rosen and Richard P. Sergel. The responsibilities and duties of the Audit Committee are set out in the Audit Committee’s Charter, a copy of which is attached as Appendix “D” to this AIF.

The Board believes that the composition of the Audit Committee reflects a high level of financial literacy and experience. Each member of the Audit Committee has been determined by the Board to be “financially literate” as such term is defined under Canadian securities laws. The Board has made these determinations based on the education and breadth and depth of experience of each member of the Audit Committee. The following is a description of the education and experience of each member of the Audit Committee that is relevant to the performance of his or her responsibilities as a member of the Audit Committee:

Kent M. Harvey, Committee Chair

Former Chief Financial Officer for PG&E Corporation, an energy-based holding company headquartered in San Francisco. PG&E Corporation is the parent company of Pacific Gas and Electric Company, one of the largest combined natural gas and electric energy companies in the United States. In over 33 years with PG&E Corporation, Mr. Harvey held progressively senior roles, including Senior Vice President and Chief Financial Officer 2009 to 2015, Senior Vice President, Chief Risk and Audit Officer 2005 to 2009. He was Senior Vice President, Chief Financial Officer and Treasurer with Pacific Gas and Electric Company, a subsidiary of PG&E Corporation, from 2000 to 2005. He holds a Bachelor’s degree in Economics and a Master’s degree in Engineering – Economic Systems, both from Stanford University.

B. Lynn Loewen, FCPA, FCA

Former President of Minogue Medical Inc., a healthcare organization which delivers innovative medical technologies to hospitals and clinics. Fellow of the Institute of Chartered Accountants, she has served in a number of senior roles at Bell Canada, Air Canada Jazz and Air Nova, and also was the Vice President, Financial Controls for BCE. She has served as Chair of the Audit Committee on the Public Sector Pension Investment Board and was Chair of the Finance and Administration Committee of Mount Allison University. In January 2018, she was appointed Chancellor of Mount Allison University. She holds a Bachelor of Commerce from Mount Allison University.

Andrea S. Rosen

Vice-Chair of TD Bank Financial Group and President, TD Canada Trust from 2002 to 2005. From 2001 to 2002, Executive Vice President of TD Commercial Banking and Vice Chair TD Securities. Before joining TD Bank, was Vice President of Varity Corporation from 1991 to 1994 and worked at Wood Gundy Inc. (later CIBC-Wood Gundy) in a variety of roles from 1981 to 1990, eventually becoming Vice President and Director. Holds a Bachelor of Laws from Osgoode Hall Law School and a Masters of Business Administration from the Schulich School of Business at York University. She received a Bachelor of Arts from Yale University. Ms. Rosen is a Director and member of the Audit Committee of Ceridian HCM Holding Inc., a global human capital management software company, and Director and member of the Audit Committee of Manulife Financial Corporation, an issuer listed on The Toronto Stock Exchange, New York Stock Exchange, The Stock Exchange of Hong Kong, and the Philippine Stock Exchange. She is a Director of Element Fleet Management Corp., a global fleet management company. Former Director and member of the Audit Committee of Hiscox Ltd., a Bermuda-incorporated specialty insurer listed on the London Stock Exchange, and former Director of Alberta Investment Management Corporation. Member of the Board of Directors of the Institute of Corporate Directors.

Richard P. Sergel

Former President and Chief Executive Officer of the North American Electric Reliability Corporation (NERC), a regulatory authority for the bulk electricity system in North America. Before that he served as President and Chief Executive Officer of National Grid USA, and its predecessor, New England Electric System, from 1998 to 2004.

Emera Incorporated – 2021 Annual Information Form	39

Mr. Sergel is a Director and a member of the Examining and Audit Committee of State Street Corporation, a provider of financial services to institutional investors including investment servicing, investment management and investment research and trading. He previously served on the Boards of the Edison Electric Institute and the United Way of the Merrimac Valley. He was also Chair of the Consortium for Energy Efficiency. Mr. Sergel holds a Bachelor of Science in Mathematics from Florida State University, a Master of Science in Applied Mathematics from North Carolina State University and a Master of Business Administration from the University of Miami.

Audit and Non-Audit Services Pre-Approval Process

The Audit Committee is responsible for the oversight of the work of the external auditors. As part of this responsibility, the Audit Committee is required to pre-approve the audit and non-audit services performed by the external auditors in order to assure that they do not impair the external auditors’ independence from the Company. Accordingly, the Audit Committee has adopted an Audit and Non-Audit Pre-Approval Policy, which sets forth the procedures and the conditions pursuant to which services proposed to be performed by the external auditors may be pre-approved.

Unless a type of service has received the pre-approval of the Audit Committee, it will require specific approval by the Audit Committee if it is to be provided by the external auditors. Any proposed services exceeding the pre-approved cost levels will also require specific approval by the Audit Committee.

Auditors’ Fees

The aggregate fees billed by Ernst & Young LLP, the Company’s external auditors, during the fiscal years ended December 31, 2021 and 2020 respectively, were as follows:

Service Fee	2021 ()	2020 ()
AuditFees
Audit-Related Fees
TaxFees
Total

All values are in US Dollars.

Audit-related fees for Emera relate to fees associated with the audit of pension plans. Tax fees for Emera relate to the structuring of cross-border financing of Emera’s subsidiaries and affiliates as well as tax compliance services and general tax consulting advice on various matters.

CERTAIN PROCEEDINGS

To the knowledge of Emera, none of the Directors or Officers of the Company:

(1)	are, as at the date of this AIF, or have been, within ten years before the date of this AIF, a director, chief<br>executive officer or chief financial officer of any company that:
(a)	was subject to an Order that was issued while the Director or Officer was acting in the capacity as director, chief<br>executive officer or chief financial officer; or
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(b)	was subject to an Order that was issued after the Director or Officer ceased to be a director, chief executive officer<br>or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer of chief financial officer;
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(2)	are, as at the date of this AIF, or have been within ten years before the date of this AIF, a director or executive<br>officer of any company that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject<br>to or instituted any proceedings, arrangements or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets;
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Emera Incorporated – 2021 Annual Information Form	40
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(3)	have, within the ten years before the date of this AIF, become bankrupt, made a proposal under any legislation<br>relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the proposed nominee; or<br>
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(4)	have been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a<br>securities regulatory body or has entered in a settlement agreement with a securities regulatory body, or is subject to any penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable<br>investor making an investment decision.
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CONFLICTS OF INTEREST

There are no existing or potential material conflicts of interest between Emera or any of its subsidiaries and any Director or Officer of Emera or any of its subsidiaries.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

To the knowledge of Emera, there are no legal proceedings that individually or together could potentially involve claims against Emera or its subsidiaries for damages totaling 10 per cent or more of the current assets of Emera, exclusive of interest and costs.

During Emera’s most recently completed financial year, there have been no (a) penalties or sanctions imposed against Emera by a court relating to securities legislation or by a securities regulatory authority, (b) other penalties or sanctions imposed by a court or regulatory body against Emera that would likely be considered important to a reasonable investor in making an investment decision, and (c) settlement agreements entered into by Emera before a court relating to securities legislation or with a securities

regulatory authority.

NO INTEREST OFMANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

None of the following persons or companies, namely (a) a Director or Officer of Emera, (b) a person or company that is the direct or indirect beneficial owner of, or who exercises control or direction over, more than 10 per cent of any class or series of Emera’s outstanding voting securities, or (c) an associate or affiliate of any person or company named in (a) or (b), had a material interest in any transaction involving Emera within Emera’s last three completed financial years or during the current financial year that has materially affected or is reasonably expected to materially affect Emera.

MATERIAL CONTRACTS

Emera did not enter into any material contracts outside the ordinary course of business during the year ended December 31, 2021, nor has it entered into any material contracts outside the ordinary course of business prior to the year ended December 31, 2021 that are still in effect as at the date of this AIF.

TRANSFER AGENT AND REGISTRAR

TSX Trust Company acts as Emera’s transfer agent and registrar for Emera’s common shares and first preferred shares. Registers for the registration and transfer of these securities of Emera are kept at TSX Trust Company’s principal offices in Halifax, Montreal and Toronto.

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EXPERTS

Ernst & Young LLP are the external auditors of Emera. Ernst & Young LLP report that they are independent in the context of the CPA Code of Professional Conduct of the Chartered Professional Accountants of Nova Scotia and are in compliance with Rule 3520 of the Public Company Accounting Oversight Board (United States).

ADDITIONAL INFORMATION

Additional information relating to Emera may be found on SEDAR at www.sedar.com or upon request to the Corporate Secretary, Emera Incorporated, P.O. Box 910, Halifax, N.S., B3J 2W5, telephone (902) 428-6096 or fax (902) 428-6171. Additional information, including Directors’ and Officers’ remuneration and indebtedness, principal holders of Emera’s securities and securities authorized for issuance under equity compensation plans, is contained in Emera’s information circular for the most recent annual meeting of Emera’s common shareholders. Additional financial information is provided in Emera’s Audited Financial Statements and MD&A.

At any time, Emera will provide to any person upon request to the Corporate Secretary, a copy of the Emera Code of Conduct. Alternatively, a copy of the Emera Code of Conduct is available electronically under Emera’s profile on SEDAR at www.sedar.com and on its corporate website at www.emera.com.

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APPENDIX “A” - Definitions of Certain Terms

For convenience, certain terms used throughout this AIF shall have the following meanings:

“adjusted net income” has the meaning ascribed to it in the “Non-GAAP Financial Measures” section of the MD&A, which is incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com;

“AFUDC” means allowance for funds used during construction and represents the cost of financing regulated construction projects and is capitalized to the cost of property, plant and equipment, where permitted by the regulator;

“AIF” or “Annual Information Form” means this 2021 Annual Information Form of Emera;

“AMI” means advanced metering infrastructure;

“AST Canada” means AST Trust Company (Canada);

“Atlantic Provinces” means the region of Canada consisting of the Provinces of New Brunswick, Newfoundland and Labrador, Nova Scotia and Prince Edward Island;

“ATM Program” means an at-the-market distribution program allowing Emera to issue common shares from treasury at the prevailing market price.

“Audited Financial Statements” means the audited consolidated financial statements of Emera as at and for the years ended December 31, 2021 and December 31, 2020, together with the auditors’ report thereon, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com;

“BahamasDRs” means the DRs listed on BISX;

“Barbados DRs” means the DRs listed on the BSE;

“Bayside” means a 290 MW gas-fired electricity generating facility in Saint John, New Brunswick.

“BBD” means Barbadian dollars;

“BISX” means The Bahamas International Securities Exchange;

“Bear Swamp” means Bear Swamp Power Company, LLC, a 633 MW pumped storage hydroelectric company incorporated under the laws of the State of Delaware in which Emera indirectly holds a 50 per cent interest;

“BLPC” means Barbados Light & Power Company Limited, a vertically integrated electric utility company

incorporated under the laws of Barbados and a wholly-owned, direct subsidiary of ECI;

“Board” means the Board of Directors of Emera;

“Brooklyn Energy” means Brooklyn Power Corporation, a 30 MW biomass co-generation company incorporated under the laws of the Province of Nova Scotia and a wholly-owned direct subsidiary of Emera;

“Brunswick Pipeline” means the pipeline delivering re-gasified natural gas from the Canaport LNG gas terminal near Saint John, New Brunswick to markets in the Northeastern United States, which is owned directly by EBPC;

“BSD” means Bahamian dollars;

“BSE” means the Barbados Stock Exchange;

“CAD” means Canadian dollars;

“CAIR” means the Clean Air Interstate Rule;

“CER” or “Canada Energy Regulator”, the independent regulator of EBPC.

“COVID-19” means an infectious respiratory illness caused by the 2019 novel coronavirus;

“COMFIT” means the Nova Scotia Community Feed-in Tariff program which is offered by the Province of Nova Scotia and enables community organizations to be involved in renewable electricity generation;

“Companies Act Relief” means an order of the Nova Scotia Securities Commission pursuant to the Companies Act (Nova Scotia) exempting Emera from the requirement to prepare its annual financial statements in accordance with IFRS;

“Company” means Emera;

“CSAPR” means Cross-State Air Pollution Rule;

“Directors” mean the directors of Emera and “Director” means any one of them;

“Dividend Reinvestment Plan” or “DRIP” means the Company’s Common Shareholders’ Dividend Reinvestment and Share Purchase Plan;

“Domlec” means Dominica Electricity Services Limited, an integrated electric utility on the island of Dominica, incorporated under the laws of the Commonwealth of Dominica, and an indirect subsidiary of Emera, through ECI;

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“DR” means a depositary receipt representing common shares of Emera;

“EBPC” or “Emera Brunswick Pipeline Company” means Emera Brunswick Pipeline Company Ltd., a company incorporated under the federal laws of Canada and a wholly-owned, indirect subsidiary of Emera;

“ECC” means NSPI Energy Control Center;

“ECI” means Emera (Caribbean) Incorporated, a company incorporated under the laws of Barbados and an indirect subsidiary of Emera and the parent company of BLPC, GBPC, Domlec and Lucelec;

“ECRC” means the environmental cost recovery clause;

“Electricity Plan Act” means the Electricity Plan Implementation (2015) Act (Nova Scotia);

“Emera” means Emera Incorporated, a public company incorporated under the laws of the Province of Nova Scotia and traded on the TSX under the symbol “EMA”;

“Emera Energy” means the businesses of Emera Energy Services, Brooklyn Energy and Bear Swamp;

“Emera Energy LP” means a wholly-owned subsidiary of Emera formed under the laws of the Province of Nova Scotia;

“Emera Energy Services” or “EES” means Emera Energy LP and Emera Energy Services, Inc., a natural gas and electricity marketing and trading company and a wholly-owned, indirect subsidiary of Emera incorporated under the laws of the State of Delaware, which together form a natural gas and electricity marketing and trading business;

“Emera Maine” means the company existing under the laws of the State of Maine and formerly a wholly-owned indirect subsidiary of Emera;

“ENL” or “Emera Newfoundland and Labrador” means Emera Newfoundland and Labrador Holdings Incorporated, a company incorporated under the laws of the Province of Newfoundland and Labrador and a wholly-owned, direct subsidiary of Emera, and the parent company of NSP Maritime Link Inc. and ENL Island Link Inc.;

“ENL Island Link Inc.” means ENL Island Link Incorporated, a company incorporated under the laws of the Province of Newfoundland and Labrador and a wholly-owned, direct subsidiary of ENL;

“EPA” means the U.S. Environmental Protection Agency;

“ETL” means Emera Technologies LLC, a limited liability company incorporated under the laws of Delaware and a wholly-owned, indirect subsidiary of Emera.

“Exemptive Relief” means the relief granted to Emera by Canadian securities regulators allowing it to continue to report its financial results in accordance with USGAAP;

“Fair Trading Commission,Barbados” or “FTC” means the independent regulator of BLPC;

“FAM” means the fuel adjustment mechanism established by the UARB;

“FCM” means forward capacity market;

“FERC” means the United States Federal Energy Regulatory Commission;

“Fitch” means the credit rating agency Fitch Ratings Inc;

“First Preferred Shares” means each series of Emera’s authorized first preferred shares, namely its Series 2016-A Conversion, First Preferred Shares, Series A First Preferred Shares, Series B First Preferred Shares, Series C First Preferred Shares, Series D First Preferred Shares, Series E First Preferred Shares, Series F First Preferred Shares, Series G First Preferred Shares Series H First Preferred Shares, Series I First Preferred Shares Series J First Preferred Shares and Series L First Preferred Shares;

“FPSC” means the Florida Public Service Commission, the regulator of Tampa Electric and PGS;

“GBPA” means The Grand Bahama Port Authority, the regulator of GBPC;

“GBPC” or “Grand Bahama Power Company” means Grand Bahama Power Company Limited, a vertically integrated electric utility company incorporated under the laws of the Commonwealth of The Bahamas and an indirect subsidiary of ECI;

“Government of Canada BondYield” on any date means the yield to maturity on such date (assuming semi-annual compounding) of a Canadian dollar denominated non-callable Government of Canada bond with a term to maturity of five years as quoted as of 10:00 a.m. (Toronto time) on such date and which appears on the Bloomberg Screen GCAN5YR Page on such date; provided that, if such rate does not appear on the Bloomberg Screen GCAN5YR Page on such date, the Government of Canada Bond Yield will mean the average of the yields determined by two registered Canadian investment dealers selected by the Company as being the yield to maturity on such date (assuming semi-annual compounding) which a

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Canadian dollar denominated non-callable Government of Canada bond would carry if issued in Canadian dollars at 100 per cent of its principal amount on such date with a term to maturity of five years;

“Government of Canada T-Bill Rate” means, for any quarterly floating rate period, the average yield expressed as a percentage per annum on three month Government of Canada treasury bills, as reported by the Bank of Canada, for the most recent treasury bills auction preceding the applicable floating rate calculation date;

“GWh” means the amount of electricity measured in gigawatt hours;

“Hybrid Notes” means the $1.2 billion USD unsecured, fixed-to-floating subordinated notes due 2076;

“ICDU” means ICD Utilities Limited, a company incorporated under the laws of the Commonwealth of The Bahamas, and an indirect subsidiary of ECI;

“IFRS” means International Financial Reporting Standards;

“Interest Reset Date” means June 15, 2026, and on every quarter thereafter that the Hybrid Notes are outstanding until their maturity on June 15, 2076;

“IPPs” means independent power producers;

“IRCD” means the Independent Regulatory Commission, Dominica, the independent regulator of Domlec;

“ISO-NE” means ISO-New England, an independent, non-profit regional transmission organization which oversees the operation of New England’s bulk electric power system and transmission lines, generated and transmitted by its member utilities;

“km” means kilometre(s);

“Labrador-Island Transmission Link Project” or “LIL” means an electricity transmission project in Newfoundland and Labrador being developed by Nalcor, which will enable the transmission of the Muskrat Falls energy between Labrador and the island of Newfoundland;

“LNG” means liquefied natural gas;

“Lucelec” means St. Lucia Electricity Services Limited, a company incorporated under the laws of St. Lucia in which Emera holds an indirect 19.1% interest through ECI;

“M&NP” means the Maritimes & Northeast Pipeline, a pipeline that transports natural gas between the

Maritime Provinces and New England, in which Emera holds an indirect 12.9 per cent interest;

“Maritime Link” means the transmission project which includes two 170-km sub-sea cables between the island of Newfoundland and the Province of Nova Scotia, developed by NSP Maritime Link Inc.;

“Maritime Provinces” means the region of Canada consisting of the Provinces of Nova Scotia, New Brunswick and Prince Edward Island;

“MD&A” means Emera’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2021, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com;

“Moody’s” means the credit rating agency Moody’s Investor Services, Inc. a subsidiary of Moody’s Corporation;

“MW” means the amount of power measured in megawatts;

“Nalcor” means Nalcor Energy, a company that is incorporated under a special act of the Legislature of the Province of Newfoundland and Labrador as a Crown corporation;

“NB Power” means New Brunswick Power Corporation, a provincial Crown corporation formed under the laws of the Province of New Brunswick, responsible for the generation, transmission and distribution of electricity in the Province of New Brunswick;

“NEGG Facilities” means a three-facility, 1,115 MW combined-cycle gas-fired electricity generating investment in the Northeastern United States, comprising Bridgeport Energy (560 MW) in Bridgeport, Connecticut; Tiverton Power (290 MW) in Tiverton, Rhode Island; and Rumford Power (265 MW) in Rumford, Maine;

“New England” means the region of the United States consisting of the States of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont;

“NMGC” means New Mexico Gas Company, Inc., a regulated gas distribution utility incorporated under the laws of Delaware and serving customers across New Mexico;

“NMPRC” means the New Mexico Public Regulation Commission, the regulator of NMGC;

“Northeastern United States” means the region of the United States consisting of New England and the States of New Jersey, New York and Pennsylvania;

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“NS Block” means the electricity transmitted through the Maritime Link from the Muskrat Falls hydroelectric project

“NSP Maritime Link Inc.” or “NSPML” means NSP Maritime Link Incorporated, a wholly-owned direct subsidiary of ENL, incorporated under the laws of the Province of Newfoundland and Labrador, that developed the Maritime Link;

“NSPI” or “Nova Scotia Power” means Nova Scotia Power Incorporated, a vertically integrated electric utility incorporated under the laws of the Province of Nova Scotia and a wholly-owned direct and indirect subsidiary of Emera;

“OATT” means the ISO-NE Open Access Transmission Tariff;

“Officers” mean the executive officers of Emera and “Officer” means any one of them;

“OM&G” means operating, maintenance and general;

“Order” means a cease trade order, an order similar to a cease trade order or an order that denies a company access to any exemption under securities legislation that is in effect for a period of more than 30 consecutive days;

“PGAC” means purchased gas adjustment clause;

“PGS” means the Peoples Gas System Division of TEC, a regulated gas distribution utility, serving customers across Florida;

“Privatization Act” means the Nova Scotia Power Privatization Act, S.N.S., 1992, c.8 - and all amendments thereto;

“Public Utilities Act” means the Public Utilities Act (Nova Scotia);

“Rating Agencies” means collectively Fitch, Moody’s and S&P, and “Rating Agency” means any one of the Rating Agencies;

“RECL” means Repsol Energy Canada Ltd.;

“Reorganization Act” means the Nova Scotia Power Reorganization (1998) Act, S.N.S., 1998, c.19 - and all amendments thereto;

“Repsol” means Repsol S.A, the parent company of RECL;

“ROE” means return on equity;

“S&P” means the credit rating agency S&P Global Ratings, a division of S&P Global Inc.;

“Sable Wind Project” means a 14 MW wind farm near Canso, Nova Scotia;

“SeaCoast” means SeaCoast Gas Transmission, LLC, a company incorporated under the laws of the State of Delaware and a wholly-owned subsidiary of TECO Energy;

“Securities Act” United States Securities Act of 1933, as amended*;*

“SEDAR” means the System for Electronic Documents Analysis and Retrieval, which can be found at www.sedar.com;

“Series 2016-A Conversion, First Preferred Shares” means the cumulative preferential first preferred shares, Series 2016-A of Emera;

“Series A First Preferred Shares” means the cumulative 5-year rate reset first preferred shares, Series A of Emera;

“Series B First Preferred Shares” means the cumulative floating rate first preferred shares, Series B of Emera;

“Series C First Preferred Shares” means the cumulative rate reset first preferred shares, Series C of Emera;

“Series D First Preferred Shares” means the cumulative floating rate first preferred shares, Series D of Emera;

“Series E First Preferred Shares” means the cumulative redeemable first preferred shares, Series E of Emera;

“Series F First Preferred Shares” means the cumulative rate reset first preferred shares, Series F of Emera;

“Series G First Preferred Shares” means the cumulative floating rate first preferred shares, Series G of Emera;

“Series H First Preferred Shares” means the cumulative minimum rate reset first preferred shares, Series H of Emera;

“Series I First Preferred Shares” means the cumulative floating rate first preferred shares, Series I of Emera;

“Series J First Preferred Shares” means the cumulative minimum rate reset first preferred shares, Series J of Emera;

“Series K First Preferred Shares” means the cumulative floating rate first preferred shares, Series K of Emera;

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“Series L First Preferred Shares” means the cumulative redeemable first preferred shares, Series L of Emera;

“SO2” means sulphur dioxide;

“SoBRA” means solar base rate adjustment;

“South Canoe Project” means a 102 MW wind farm near New Russell, Nova Scotia;

“Tampa Electric” means the Tampa Electric Division of TEC, an integrated regulated electric utility, serving customers in West Central Florida;

“TEC” means Tampa Electric Company, a wholly-owned subsidiary of TECO Energy, incorporated under the laws of the State of Florida with regulated electric and gas utilities in Florida, collectively, Tampa Electric and PGS;

“TECO Energy” means TECO Energy, Inc., an energy-related holding company incorporated under the laws of the State of Florida with regulated electric and gas utilities in Florida and New Mexico;

“TSX” means The Toronto Stock Exchange;

“UARB” means the Nova Scotia Utility and Review Board, the independent regulator of NSPI;

“USD” means U.S. dollars; and

“USGAAP” means the accounting principles which are recognized as being generally accepted and which are in effect from time to time in the U.S. as codified by the Financial Accounting Standards Board, or any successor institute

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APPENDIX “B” – Summary of Terms and Conditions of Authorized Series of FirstPreferred Shares

As of December 31, 2021, the following series of First Preferred Shares have been authorized:

Series A, B, C, D, E, F, G, H, I, J, K and L First Preferred Shares

Holders of the First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except: (i) where entitled by law; (ii) for meetings of the holders of first preferred shares as a class and holders of First Preferred Shares as a series; and (iii) in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the First Preferred Shares.

In any instance where the holders of First Preferred Shares are entitled to vote, each holder shall have one vote for each Preferred Share, subject to the restrictions described under “Share Ownership Restrictions” below.

Holders of Series A, C, F, H and J First Preferred Shares are entitled to receive fixed cumulative preferential cash dividends, as and when declared by the Board, to be reset periodically on established dates to an annualized rate equal to the sum of the then five-year Government of Canada Bond Yield, calculated at the start of the applicable five-year period, and a spread as set forth in the table below (subject, (i) in the case of the Series H preferred shares, to a fixed minimum reset of 4.90 per cent and (ii) in the case of the Series J preferred shares, to a fixed minimum reset of 4.25 per cent). Holders of the Series A, C, F, and H First Preferred Shares have the right to convert their shares into an equal number of Series B, D, G, and I First Preferred Shares, respectively, subject to certain conditions, on such conversion dates as set forth in the table below.

Holders of Series B, D, G, I and K First Preferred Shares will be entitled to receive floating rate cumulative preferential cash dividends, as and when declared by the Board. The dividends are payable quarterly, in the amount per share determined by multiplying the applicable quarterly floating dividend rate, which is the sum of the three-month Government of Canada T-Bill Rate , recalculated quarterly, on the applicable reset date plus a spread as set forth in the table below.

The Series A, C, F, H and J First Preferred Shares are redeemable by Emera, in whole or in part under certain circumstances by the payment of cash on the dates set forth in the table below at a price of $25.00 per share plus any accrued and unpaid dividends.

The Series B, D, G, I and K First Preferred Shares are redeemable by Emera, in whole or in part under certain circumstances after their respective initial redemption dates by payment in cash as set forth in the table below at a price equal to (i) $25.00 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions as set out in the table below or (ii) $25.50 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on any other date.

Subject to certain conditions including the right of Emera to redeem, holders of the Series A, C, F, H and J First Preferred Shares, have the right to convert any or all of their Series A, C, F, H and J First Preferred Shares into an equal number of Series B, D, G, I and K First Preferred Shares, respectively. In addition, the Series A, C, F, H and J First Preferred Shares may be automatically converted by Emera into Series B, D, G, I and K First Preferred Shares, respectively if Emera determines that, following conversion by the holders, there would be less than 1,000,000 Series A, C, F, H and J First Preferred Shares outstanding, respectively.

Subject to automatic conversion conditions including the right of Emera to redeem the Series B, D, G, I and K First Preferred Shares, the holders of Series B, D, G, I and K First Preferred Shares have the right to convert any or all of their Series B, D, G, I and K First Preferred Shares into an equal number of Series A, C, F, H and J First Preferred Shares respectively. In addition, Series B, D, G, I and K First Preferred Shares may be automatically converted by Emera into Series A, C, F, H and J First Preferred Shares, respectively if Emera determines that, following conversion by the holders, there would be less than 1,000,000 Series B, D, G, I and K First Preferred Shares outstanding.

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Holders of Series E First Preferred Shares will be entitled to receive fixed cumulative preferential cash dividends as and when declared by the Board in the amount of $1.125 per share per annum in perpetuity, subject to certain redemption rights. The Series E First Preferred Shares were not redeemable by the Company prior to August 18, 2018. The Series E First Preferred Shares are redeemable on or after August 18, 2018 by Emera in whole or in part, at the Company’s option without the consent of the holder, by the payment of: $26.00 per share if redeemed before August 15, 2019; $25.75 per share if redeemed on or after August 15, 2019 but before August 15, 2020; $25.50 per share if redeemed on or after August 15, 2020 but before August 15, 2021; $25.25 per share if redeemed on or after August 15, 2021 but before August 15, 2022; and $25.00 per share if redeemed on or after August 15, 2022; together, in each case, with all accrued and unpaid dividends up to but excluding the date fixed for redemption.

Holders of Series L First Preferred Shares will be entitled to receive fixed cumulative preferential cash dividends as and when declared by the Board in the amount of $1.150 per share per annum in perpetuity, subject to certain redemption rights. The Series L First Preferred Shares were not redeemable by the Company prior to November 15, 2026. The Series L First Preferred Shares are redeemable on or after November 15, 2026 by Emera in whole or in part, at the Company’s option without the consent of the holder, by the payment of: $26.00 per share if redeemed before November 15, 2027; $25.75 per share if redeemed on or after November 15, 2027 but before November 15, 2028; $25.50 per share if redeemed on or after November 15, 2028 but before November 15, 2029; $25.25 per share if redeemed on or after November 15, 2029 but before November 15, 2030; and $25.00 per share if redeemed on or after November 15, 2030; together, in each case, with all accrued and unpaid dividends up to but excluding the date fixed for redemption.

Series of First<br> <br>Preferred Shares	Initial Redemption<br><br><br>Date	Redemption/Conversion/Interest Reset dates	Spreads
Series A	August 15, 2015	August 15, 2020 and every fifth year thereafter	1.84%
Series B	August 15, 2020	August 15, 2025 and every fifth year thereafter	1.84%
Series C	August 15, 2018	August 15, 2023 and every fifth year thereafter	2.65%
Series D	_	August 15, 2023 and every fifth year thereafter	2.65%
Series E	August 15, 2018	_	_
Series F	February 15, 2020	February 15, 2025 and every fifth year thereafter	2.63%
Series G	_	February 15, 2025 and every fifth year thereafter	2.63%
Series H	August 15, 2023	August 15, 2028 and every fifth year thereafter	2.54%
Series I	_	August 15, 2028 and every fifth year thereafter	2.54%
Series J	May 15, 2026	May 15, 2031 and every fifth year thereafter	3.28%
Series K	_	May 15, 2031 and every fifth year thereafter	3.28%
Series L	November 15, 2026	_	_

Series 2016-A Conversion, First Preferred Shares

The Series 2016-A Conversion, First Preferred Shares were authorized pursuant to the Hybrid Notes offering in June 2016. As at December 31, 2021, there were no Series 2016-A Conversion, First Preferred Shares issued and outstanding.

Holders of Series 2016-A Conversion, First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except: (i) where entitled by law; (ii) for meetings of the holders of first preferred shares as a class and holders of Series 2016-A Conversion, First Preferred Shares as a series; and (iii) in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the Series 2016-A Conversion, First Preferred Shares.

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In any instance where the holders of Series 2016-A Conversion, First Preferred Shares are entitled to vote, each holder shall have one vote for each Series 2016-A Conversion, First Preferred Share, subject to the restrictions described under “Share Ownership Restrictions” below.

Holders of each series of Series 2016-A Conversion, First Preferred Shares will be entitled to receive cumulative preferential cash dividends, if, as and when declared by the Board, at the same rate as would have accrued on the related series of Hybrid Notes (had such Hybrid Notes remained outstanding). The Series 2016-A Conversion, First Preferred Shares do not have a fixed maturity date.

The Series 2016-A Conversion, First Preferred Shares are redeemable by Emera on June 15, 2026. After that date, Emera may redeem at any time all, or from time to time any part, of the outstanding Series 2016-A Conversion, First Preferred Shares, without the consent of the holders, by the payment of an amount in cash for each such share so redeemed of USD$1,000 per share together with an amount equal to all accrued and unpaid dividends thereon.

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APPENDIX “C” - MONTHLY TRADING VOLUME AND HIGH AND LOW PRICE FOR EMERA’S SECURITIES IN 2021

	Common<br><br><br>Shares	Depositary Receipts		Series of First Preferred Shares
		Barbados<br><br><br>BBD (1)	Bahamas<br> <br>BSD^(2)^	A	B	C	E	F	H	J^(3)^	L^(4)^
December<br><br><br>High ($)<br><br><br>Low ($)<br><br><br>Volume	63.71 <br> <br>58.54<br><br><br>12,069,562	24.43 <br> <br>22.68<br><br><br>0	12.47<br> <br>11.45<br><br><br>0	18.67<br> <br>17.04<br><br><br>23,565	18.26<br> <br>17.68<br><br><br>7,170	24.65<br> <br>23.38<br><br><br>57,718	25.00<br> <br>24.38<br><br><br>23,342	24.66<br> <br>23.30<br><br><br>76,408	26.56<br> <br>25.71<br><br><br>67,110	26.49<br> <br>25.75<br><br><br>210,707	25.15<br> <br>24.80<br><br><br>61,497
November<br><br><br>High ($)<br><br><br>Low ($)<br><br><br>Volume	59.65<br> <br>57.22<br><br><br>22,121,809	23.38<br> <br>22.82<br><br><br>0	11.76<br> <br>11.57<br><br><br>0	19.45<br> <br>18.36<br><br><br>26,266	19.00<br> <br>18.20<br><br><br>15,500	25.00<br> <br>24.50<br><br><br>105,389	24.75<br> <br>24.32<br><br><br>92,296	24.90<br> <br>24.35<br><br><br>27,443	26.40<br> <br>25.89<br><br><br>35,283	26.15<br> <br>25.86<br><br><br>190,384	25.20<br> <br>24.66<br><br><br>105,128
October<br><br><br>High ($)<br><br><br>Low ($)<br><br><br>Volume	59.31<br> <br>56.93<br><br><br>20,614,966	23.58<br> <br>22.35<br><br><br>0	11.98<br> <br>11.25<br><br><br>0	18.81<br> <br>17.53<br><br><br>39,975	17.21<br> <br>16.85<br><br><br>7,848	24.87<br> <br>24.10<br><br><br>60,145	25.04<br> <br>24.47<br><br><br>117,408	24.80<br> <br>24.27<br><br><br>73,735	26.68<br> <br>25.92<br><br><br>70,708	26.52<br> <br>25.76<br><br><br>121,595	25.60<br> <br>24.50<br><br><br>261,481
September<br><br><br>High ($)<br><br><br>Low ($)<br><br><br>Volume	59.91<br> <br>56.87<br><br><br>11,703,369	23.33<br> <br>22.39<br><br><br>0	11.84<br> <br>11.21<br><br><br>0	17.71<br> <br>17.10<br><br><br>40,875	17.35<br> <br>16.98<br><br><br>12,795	24.46<br> <br>23.64<br><br><br>148,946	25.25<br> <br>24.76<br><br><br>389,756	24.44<br> <br>23.85<br><br><br>24,533	26.54<br> <br>25.72<br><br><br>134,525	27.00<br> <br>26.11<br><br><br>264,923	25.68<br> <br>25.11<br><br><br>1,160,554
August<br><br><br>High ($)<br><br><br>Low ($)<br><br><br>Volume	60.26<br> <br>58.00<br><br><br>17,980,519	23.34<br> <br>22.97<br><br><br>0	11.06<br> <br>11.06<br><br><br>182	17.55<br> <br>16.70<br><br><br>36,050	17.40<br> <br>16.85<br><br><br>8,901	24.35<br> <br>23.40<br><br><br>172,005	25.00<br> <br>24.65<br><br><br>45,151	24.50<br> <br>23.81<br><br><br>100,088	26.76<br> <br>25.46<br><br><br>130,307	27.00<br> <br>26.50<br><br><br>58,885	-<br> <br>-<br><br><br>-
July<br><br><br>High ($)<br><br><br>Low ($)<br><br><br>Volume	58.83<br> <br>55.96<br><br><br>20,296,590	22.99<br> <br>22.35<br><br><br>0	10.02<br> <br>10.02<br><br><br>456	17.88<br> <br>17.03<br><br><br>119,198	16.95<br> <br>16.75<br><br><br>28,063	24.44<br> <br>23.57<br><br><br>64,220	24.97<br> <br>24.56<br><br><br>85,872	24.96<br> <br>23.45<br><br><br>322,950	26.69<br> <br>26.10<br><br><br>71,706	27.46<br> <br>26.01<br><br><br>316,840	-<br> <br>-<br><br><br>-
June<br><br><br>High ($)<br><br><br>Low ($)<br><br><br>Volume	58.02<br> <br>55.90<br><br><br>11,322,614	23.41<br> <br>22.69<br><br><br>0	11.90<br> <br>11.61<br><br><br>0	18.02<br> <br>16.90<br><br><br>68,052	17.98<br> <br>16.48<br><br><br>11,003	24.48<br> <br>23.45<br><br><br>75,014	24.95<br> <br>24.40<br><br><br>97,359	23.95<br> <br>23.27<br><br><br>206,620	26.91<br> <br>25.80<br><br><br>167,992	26.81<br> <br>26.13<br><br><br>138,576	-<br> <br>-<br><br><br>-
May<br><br><br>High ($)<br><br><br>Low ($)<br><br><br>Volume	56.81<br> <br>55.42<br><br><br>17,367,266	23.17<br> <br>22.30<br><br><br>0	11.73<br> <br>11.36<br><br><br>0	17.33<br> <br>16.06<br><br><br>20,573	17.27<br> <br>15.46<br><br><br>9,305	24.06<br> <br>22.73<br><br><br>149,082	24.63<br> <br>23.81<br><br><br>107,242	23.33<br> <br>21.43<br><br><br>131,187	26.51<br> <br>25.65<br><br><br>100,350	26.20<br> <br>25.25<br><br><br>310,882	-<br> <br>-<br><br><br>-
April<br><br><br>High ($)<br><br><br>Low ($)<br><br><br>Volume	58.67<br> <br>55.44<br><br><br>22,403,708	22.77<br> <br>21.84<br><br><br>0	10.50<br> <br>10.50<br><br><br>2,300	16.38<br> <br>16.00<br><br><br>99,202	16.20<br> <br>15.74<br><br><br>4,650	22.98<br> <br>22.00<br><br><br>171,615	24.45<br> <br>24.10<br><br><br>66,597	21.86<br> <br>21.26<br><br><br>122,121	25.95<br> <br>25.42<br><br><br>124,163	25.35<br> <br>24.85<br><br><br>1,503,508	-<br> <br>-<br><br><br>-
March<br><br><br>High ($)<br><br><br>Low ($)<br><br><br>Volume	56.27<br> <br>50.30<br><br><br>17,936,313	22.04<br> <br>19.69<br><br><br>0	10.71<br> <br>10.40<br><br><br>9,100	16.34<br> <br>15.37<br><br><br>120,695	16.20<br> <br>15.00<br><br><br>21,613	22.90<br> <br>20.90<br><br><br>288,647	24.54<br> <br>23.79<br><br><br>133,802	21.60<br> <br>19.42<br><br><br>364,870	25.84<br> <br>25.11<br><br><br>276,913	-<br> <br>-<br><br><br>-	-<br> <br>-<br><br><br>-
February<br><br><br>High ($)<br><br><br>Low ($)<br><br><br>Volume	53.90<br> <br>49.66<br><br><br>25,227,378	20.62<br> <br>19.48<br><br><br>0	9.50<br> <br>9.50<br><br><br>20,000	15.60<br> <br>13.59<br><br><br>257,241	14.90<br> <br>13.21<br><br><br>4,885	21.89<br> <br>19.40<br><br><br>130,478	24.49<br> <br>23.30<br><br><br>64,780	20.31<br> <br>19.01<br><br><br>131,614	25.91<br> <br>25.11<br><br><br>206,166	-<br> <br>-<br><br><br>-	-<br> <br>-<br><br><br>-
January<br><br><br>High ($)<br><br><br>Low ($)<br><br><br>Volume	54.60<br> <br>51.73<br><br><br>26,550,629	20.91<br> <br>20.01<br><br><br>0	10.71<br> <br>10.15<br><br><br>0	13.75<br> <br>12.40<br><br><br>167,999	13.00<br> <br>12.01<br><br><br>5,780	19.94<br> <br>17.58<br><br><br>166,171	24.05<br> <br>23.70<br><br><br>101,876	19.22<br> <br>17.61<br><br><br>84,566	25.75<br> <br>25.31<br><br><br>187,305	-<br> <br>-<br><br><br>-	-<br> <br>-<br><br><br>-
(1)	The Barbados DRs trade on the BSE. During those months in 2021 when the Volume Traded was zero (0), the table above<br>indicates the high and low trading prices of the Barbados DRs relative to those of Emera’s common shares on the TSX.
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(2)	The Bahamas DRs trade on the BISX. During those months in 2021 when the Volume Traded was zero (0), the table above<br>indicates the high and low trading prices of the Bahamas DRs relative to those of Emera’s common shares on the TSX.
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(3)	The Series J First Preferred Shares were issued on April 6, 2021.
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(4)	The Series L First Preferred Shares were issued on September 24, 2021.
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Emera Incorporated – 2021 Annual Information Form	51
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February 2022
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APPENDIX “D” - EMERA INCORPORATED AUDIT COMMITTEE CHARTER

PART I

MANDATE AND RESPONSIBILITIES

Committee Purpose

There shall be a committee of the Board of Directors (the “Board”) of Emera Inc. (“Emera”) which shall be known as theAudit Committee (the “Committee”). The Committee shall assist the Board in discharging its oversight responsibilities concerning:

-	the quality and integrity of Emera’s financial statements;
-	the effectiveness of Emera’s internal control systems over financial reporting;
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-	the internal audit and assurance process;
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-	the qualifications, independence and performance of the external auditors;
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-	major financial risk exposures;
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-	Emera’s compliance with legal requirements and securities regulations in respect of financialstatements and financial reporting; and
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-	any other duties set out in this Charter or delegated to the Committee by the Board.
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1.	Financial Reporting
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a)	The Committee shall be responsible for reviewing, assessing the completeness and clarity of the disclosures<br>in, and recommending to the Board for approval:
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(i)	the audited annual financial statements of Emera, all related Management’s Discussion and Analysis, and<br>earnings press releases;
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(ii)	any documents containing Emera’s audited financial statements; and,
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(iii)	the quarterly financial statements, all related Management’s Discussion and Analysis, and earnings<br>press releases.
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b)	The Board may delegate the approval of the quarterly financial statements, all related Management’s<br>Discussion and Analysis, and earnings press releases to the Committee.
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c)	The Committee shall oversee and assess that adequate procedures are in place for the review of public<br>disclosure of financial information.
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2.	External Auditors
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a)	The Committee shall evaluate and recommend to the Board the external auditor to be nominated for the purpose<br>of preparing or issuing the auditor’s report or performing other audit, review, or attest services for Emera, and the compensation of such external auditors.
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b)	Once appointed, the external auditor shall report directly to the Committee, and the Committee shall oversee<br>the work of the external auditor concerning the preparation or issuance of the auditor’s report or the performance of other audit, review or attest services for Emera.
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Emera Incorporated – 2021 Annual Information Form	52
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c)	The Committee shall be responsible for resolving disagreements between management and the external auditor<br>concerning financial reporting.
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d)	At least annually, the Committee shall obtain and review a report by the external auditors describing:<br>(i) the firm’s internal quality control procedures; (ii) any material issues raised by the most recent internal quality control review, or peer review, of the firm, or by any inquiry or investigation by governmental or professional<br>authorities, within the preceding five years, with respect to one or more external audits carried out by the firm, and any steps taken to deal with any such issues; and (iii) all relationships between the external auditors and Emera (to assess<br>the auditors’ independence).
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e)	The Committee shall annually evaluate the auditors’, including the lead partner’s, qualifications,<br>performance, professional skepticism and independence.
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f)	The Committee shall determine that the external audit firm has a process in place to address the rotation of<br>the lead audit partner and other audit partners serving the account as required under prescribed independence rules.
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g)	Every five (5) years, the Committee shall perform a comprehensive review of the performance of the<br>external auditors over multiple years to provide further insight on the audit firm, its independence and application of professional standards.
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h)	The Committee will review differences that were noted or proposed by the external auditors, but that were<br>considered immaterial or insignificant; and any “management” or “internal control” letter issued, or proposed to be issued.
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3.	Non-Audit Services
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a)	The Committee shall be responsible for reviewing and pre-approving all non-audit services to be provided to<br>Emera, or any of its subsidiaries, by the external auditor.
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b)	The Committee may establish specific policies and procedures concerning the performance of non-audit<br>services by the external auditor so long as the requirements of applicable legislation and regulation are satisfied.
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c)	In accordance with policies and procedures established by the Committee, and applicable legislation and<br>regulation, the Committee may delegate the pre-approval of non-audit services to a member of the Committee or a sub-committee thereof.
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Emera Incorporated – 2021 Annual Information Form	53
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4.	Oversight and Monitoring of Audits
---	---
a)	The Committee shall meet with the external auditor prior to the audit to discuss the planning and staffing<br>of the audit, including the general approach, scope, areas subject to significant risk of material misstatement, estimated fees and other terms of engagement.
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b)	The Committee shall discuss with the external auditor any issues that arise with Management or the internal<br>auditors during the course of the audit and the adequacy of Management’s responses in addressing audit-related deficiencies.
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c)	The Committee shall regularly review with the external auditors any audit problems or difficulties<br>encountered during the course of the audit work, including any restrictions on the scope of the external auditors’ activities or access to requested information, and Management’s response.
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d)	The Committee shall review with Management the results of internal and external audits.<br>
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e)	The Committee shall take such other reasonable steps as it may deem necessary to oversee that the audit was<br>conducted in a manner consistent with applicable legal requirements and auditing standards of applicable professional or regulatory bodies.
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5.	Oversight and Review of Accounting Principles and Practices
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The Committee shall oversee, review and discuss with Management, the external auditor and the internal auditors:

a)	the quality, appropriateness and acceptability of Emera’s accounting principles and practices used in<br>its financial reporting, changes in Emera’s accounting principles or practices and the application of particular accounting principles and disclosure practices by Management to new transactions or events;
b)	all significant financial reporting issues and judgments made in connection with the preparation of the<br>financial statements, including the effects of alternative methods within generally accepted accounting principles on the financial statements and any “other opinions” sought by Management from an independent auditor, other than the<br>Company’s external auditors, with respect to the accounting treatment of a particular item, and other material written communications between the external auditors and management;
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c)	disagreements between Management and the external auditor or the internal auditors regarding the application<br>of any accounting principles or practices;
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d)	any material change to Emera’s auditing and accounting principles and practices as recommended by<br>Management, the external auditor or the internal auditors or which may result from proposed changes to applicable generally accepted accounting principles;
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e)	the effect of regulatory and accounting initiatives on Emera’s financial statements and other financial<br>disclosures;
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f)	any reserves, accruals, provisions, estimates or Management programs and policies, including factors that<br>affect asset and liability carrying values and the timing of revenue and expense recognition, that may have a material effect upon the financial statements of Emera;
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Emera Incorporated – 2021 Annual Information Form	54
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g)	the use of special purpose entities and the business purpose and economic effect of off-balance sheet<br>transactions, arrangements, obligations, guarantees and other relationships of Emera and their impact on the reported financial results of Emera;
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h)	any legal matter, claim or contingency that could have a significant impact on the financial statements,<br>Emera’s compliance policies and any material reports, inquiries or other correspondence received from regulators or governmental agencies and the manner in which any such legal matter, claim or contingency has been disclosed in Emera’s<br>financial statements;
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i)	the treatment for financial reporting purposes of any significant transactions which are not a normal part<br>of Emera’s operations.
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6.	Hiring Policies
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The Committee shall review and approve Emera’s hiring policy concerning partners or employees, as well as former partners and employees, of the present or former external auditors of Emera.

7.	Pension Plans

The Committee shall exercise oversight of the pension plans in accordance with the Pension Oversight Framework adopted by Emera.

8.	Oversight of Finance Matters
a)	The Committee shall review the appointments of key financial executives involved in the financial reporting<br>process of Emera, including the Chief Financial Officer.
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b)	The Committee may request for review, and shall receive when requested, material tax policies and tax<br>planning initiatives, tax payments and reporting and any pending tax audits or assessments. The Committee shall review Emera’s compliance with tax and financial reporting laws and regulations.
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c)	The Committee shall meet at least annually with Management to review and discuss Emera’s major<br>financial risk exposures and the policy steps Management has taken to monitor and control such exposures, including the use of financial derivatives, hedging activities, and credit and trading risks.
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d)	The Committee may review any investments or transactions that the Committee wishes to review, or which the<br>internal or external auditor, or any officer of Emera, may bring to the attention of the Committee within the context of this charter.
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e)	The Committee shall review financial information of material subsidiaries of Emera and any auditor<br>recommendations concerning such subsidiaries.
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f)	The Committee may request for review, and shall receive when requested, all related party transactions<br>required to be disclosed pursuant to generally accepted accounting principles, and discuss with Management the business rationale for the transactions and whether appropriate disclosures have been made.
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Emera Incorporated – 2021 Annual Information Form	55
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9.	Internal Controls
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The Committee shall oversee:

a)	the adequacy and effectiveness of the Company’s internal accounting and financial controls and the<br>recommendations of Management, the external auditor and the internal auditors for the improvement of accounting practices and internal controls; and
b)	management’s compliance with the Company’s processes, procedures and internal controls.<br>
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In exercising such oversight, the Committee shall review and discuss each of the foregoing with Management, the external auditor and the internal auditor.

The Committee will carry out the following specific duties:

c)	Review and discuss with the Chief Executive Officer and the Chief Financial Officer the procedures<br>undertaken in connection with the Chief Executive Officer and Chief Financial Officer certifications for the annual and interim filings with applicable securities regulatory authorities.
d)	Review disclosures made by Emera’s Chief Executive Officer and Chief Financial Officer during their<br>certification process for the annual and interim filing with applicable securities regulatory authorities about any significant deficiencies in the design or operation of internal controls which could adversely affect Emera’s ability to record,<br>process, summarize and report financial data or any material weaknesses in the internal controls, and any fraud involving management or other employees who have a significant role in the Emera’s internal controls.
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e)	Discuss with Emera’s Chief Legal Officer at least annually any legal matters that may have a material<br>impact on the financial statements, operations, assets or compliance policies and any material reports or inquiries received by Emera or any of its subsidiaries from regulators or governmental agencies.
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10.	Internal Auditor
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a)	The lead internal auditor shall report directly to the Committee. The Committee shall approve the<br>appointment, removal and replacement of the lead internal auditor. The Committee shall approve the remuneration of the lead internal auditor on appointment.
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b)	The Committee shall review and approve the internal audit plan, including activities, organizational<br>structure, staffing, qualifications and budget, and shall review all major changes to the plan. The Committee shall review and discuss with the internal auditor the scope, progress, and results of executing the internal audit plan. The Committee<br>shall receive reports on the status of significant findings, recommendations, and management’s responses.
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Emera Incorporated – 2021 Annual Information Form	56
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c)	The Committee shall meet periodically with the internal auditor to discuss the progress of their activities,<br>any significant findings stemming from internal audits, any issues that arise with Management, and the adequacy of Management’s responses in addressing audit-related deficiencies.
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d)	The Committee shall obtain from the internal auditor and review summaries of the significant reports to<br>Management prepared by the internal auditor, and the actual reports if requested by the Committee, and Management’s responses to such reports.
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e)	The Committee shall annually receive and review a report on the Chief Executive Officers’ expense<br>accounts.
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f)	The Committee may communicate with the internal auditor with respect to their reports and recommendations,<br>the extent to which prior recommendations have been implemented and any other matters that the internal auditor brings to the attention of the Committee.
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g)	The Committee shall, at least biennially or more frequently as it deems necessary, approve the internal<br>audit charter. The internal auditor shall confirm to the Committee annually that the function adheres to applicable professional standards. The Committee may provide feedback on the performance of the lead internal auditor as deemed necessary.<br>
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h)	The Committee shall, biennially or more frequently as it deems necessary, review the independence of the<br>internal audit function and shall make recommendations to the Board on appropriate actions to be taken which the Committee deems necessary to protect and enhance the independence of the internal audit function.
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i)	The Committee shall review the results of an external assessment, performed every five years by a qualified<br>independent assessor or assessment team, of the internal audit function in conformance with International Standards for the Professional Practice of Internal Auditing (IPPF Standards).
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11.	Complaints
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The Committee shall oversee procedures relating to the receipt, retention, and treatment of complaints received concerning accounting, internal accounting controls, or auditing matters. The Committee shall also review procedures concerning the confidential, anonymous submission of concerns by Emera’s employees relating to questionable accounting or auditing matters.

12.	Other Responsibilities

The Committee shall:

a)	Periodically review Management’s process for identifying non-compliance with legal and regulatory<br>requirements;
b)	Annually receive and review a report on executive officers’ compliance with the Company’s Code of<br>Conduct; and
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c)	Perform such other duties and exercise such powers as may be directed or delegated to the Committee by the<br>Board.
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Emera Incorporated – 2021 Annual Information Form	57
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13.	Limitation on Authority
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Nothing articulated herein is intended to assign to the Committee the Board’s responsibility to oversee Emera’s compliance with applicable laws or regulations or to expand applicable standards of liability under statutory or regulatory requirements for the Directors or the members of the Committee.

PART II

COMPOSITION

14.	Composition
a)	Emera’s Articles of Association require that the Committee shall be comprised of no less than three<br>directors none of whom may be officers or employees of Emera nor may they be an officer or employee of any affiliate of Emera. In addition, all members of the Committee shall be independent as required by applicable legislation.<br>
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b)	The Board shall appoint members to the Committee who are financially literate, as required by applicable<br>legislation, which at a minimum requires that Committee members have the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth<br>and complexity of issues that can reasonably be expected to be raised by Emera’s financial statements.
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c)	Committee members shall be appointed at the Board meeting following the election of Directors at<br>Emera’s annual shareholders’ meeting and membership may be based upon the recommendation of the Nominating and Corporate Governance Committee.
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d)	Pursuant to Emera’s Articles of Association, the Board may appoint, remove, or replace any member of<br>the Committee at any time, and a member of the Committee shall cease to be a member of the Committee upon ceasing to be a Director. Subject to the foregoing, each member of the Committee shall hold office as such until the next annual meeting of<br>shareholders after the member’s appointment to the Committee.
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e)	The Secretary of the Committee shall advise Emera’s internal and external auditors of the names of the<br>members of the Committee promptly following their election.
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PART III

COMMITTEE PROCEDURE

15.	Meetings
a)	Meetings of the Committee may be called by the Chair or at the request of any member. The Committee shall<br>meet at least quarterly.
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b)	The timing and location of meetings of the Committee, and the calling of and procedure at any such meeting,<br>shall be determined from time to time by the Committee.
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c)	Emera’s internal and external auditors shall be notified of all meetings of the Committee and shall<br>have the right to appear before and be heard by the Committee.
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Emera Incorporated – 2021 Annual Information Form	58
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d)	Emera’s internal or external auditors may request the Chair of the Committee to consider any matters<br>which the internal or external auditors believe should be brought to the attention of the Committee or the Board.
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16.	Separate Sessions
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a)	The Committee Chair shall meet periodically with the Chief Financial Officer, the lead internal auditor and<br>the external auditor in separate executive sessions to discuss any matters that the Committee or each of these groups believes should be discussed privately.
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b)	The Chief Financial Officer, the lead internal auditor and the external auditor shall have access to the<br>Committee to bring forward matters requiring its attention.
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c)	The Committee shall meet periodically without Management present.
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17.	Quorum
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Two members of the Committee present in person, by teleconferencing, or by videoconferencing, or by a combination thereof, will constitute a quorum.

18.	Chair

Pursuant to Emera’s Articles of Association, the Committee shall choose one of its members to act as Chair of the Committee, which person shall not be the Chair of Nova Scotia Power Inc.’s Audit Committee. In selecting a Committee Chair, the Committee may consider any recommendation made by the Nominating and Corporate Governance Committee.

19.	Secretary and Minutes

Pursuant to Emera’s Articles of Association, the Corporate Secretary of Emera shall act as the Secretary of the Committee. Emera’s Articles of Association require that the Minutes of the Committee be in writing and duly entered into Emera’s records, and the Minutes shall be circulated to all members of the Committee. The Secretary shall maintain all Committee records.

20.	Board Relationships and Reporting

The Committee shall:

a)	Review annually the Committee’s Charter;
b)	Oversee the appropriate disclosure of the Committee’s Charter as well as other information concerning<br>the Committee which is required to be disclosed by applicable legislation in Emera’s Annual Information Form and any other applicable disclosure documents;
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c)	Report to the Board at the next following board meeting on any meeting held by the Committee, and as<br>required, regularly report to the Board on Committee activities, issues, and related recommendations; and
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Emera Incorporated – 2021 Annual Information Form	59
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d)	Maintain free and open communication between the Committee, the external auditors, internal auditors, and<br>Management, and determine that all parties are aware of their responsibilities.
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21.	Powers
---	---

The Committee shall:

a)	examine and consider such other matters, and meet with such persons, in connection with the internal or<br>external audit of Emera’s accounts, which the Committee in its discretion determines to be advisable;
b)	have the authority to communicate directly with the internal and external auditors; and<br>
---	---
c)	have the right to inspect all records of Emera or its affiliates and may elect to discuss such records, or<br>any matters relating to the financial affairs of Emera with the officers or auditors of Emera and its affiliates.
---	---
22.	Experts and Advisors
---	---

The Committee may, in consultation with the Chairman of the Board, engage and compensate any outside adviser that it determines necessary in order to carry out its duties.

Emera Incorporated – 2021 Annual Information Form	60

EX-99.2

Exhibit 99.2

LOGO

Management’s Discussion & Analysis

As at February 14, 2022

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 2021 relative to the same quarter in 2020; for the full year of 2021 relative to 2020 and selected financial information for 2019; and its financial position as at December 31, 2021 relative to December 31, 2020. Throughout this discussion, “Emera Incorporated”, “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, Other Electric Utilities, Gas Utilities and Infrastructure, and Other.

This discussion and analysis should be read in conjunction with the Emera Incorporated annual audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2021. 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, 2021, Emera’s rate-regulated subsidiaries and investments include:

Emera Rate-Regulated Subsidiary or Equity<br> <br>Investment	Accounting Policies Approved/Examined By
Subsidiary
Tampa Electric – Electric Division of Tampa Electric Company (“TEC”)	Florida Public Service Commission (“FPSC”) and the Federal Energy Regulatory Commission (“FERC”)
Nova Scotia Power Inc. (“NSPI”)	Nova Scotia Utility and Review Board (“UARB”)
Barbados Light & Power Company Limited (“BLPC”)	Fair Trading Commission, Barbados (“FTC”)
Grand Bahama Power Company Limited (“GBPC”)	The Grand Bahama Port Authority (“GBPA”)
Dominica Electricity Services Ltd. (“Domlec”)	Independent Regulatory Commission, Dominica (“IRC”)
Peoples Gas System (“PGS”) – Gas Division of TEC	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”)
Equity Investments
NSP Maritime Link Inc. (“NSPML”)	UARB
Labrador Island Link Limited Partnership (“LIL”)	Newfoundland and Labrador Board of Commissioners of Public Utilities (“NLPUB”)
St. Lucia Electricity Services Limited (“Lucelec”)	National Utility Regulatory Commission (“NURC”)
Maritimes & Northeast Pipeline Limited Partnership and Maritimes & Northeast Pipeline, LLC (“M&NP”)	CER and FERC

On March 24, 2020, the Company completed the sale of Emera Maine. For further detail, refer to the “Significant Items Affecting Earnings” section.

All amounts are in Canadian dollars (“CAD”), except for the Florida Electric Utility, Other Electric Utilities and Gas Utilities and Infrastructure sections of the MD&A, which are reported in US dollars (“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	3
Introduction and<br>Strategic Overview	3
Non-GAAP Financial Measures	5
Consolidated<br>Financial Review	7
Significant Items<br>Affecting Earnings	7
Consolidated<br>Financial Highlights by Business Segment	8
Consolidated Income<br>Statement Highlights	9
Business Overview<br>and Outlook	13
COVID-19 Pandemic	13
Florida Electric<br>Utility	13
Canadian Electric<br>Utilities	14
Other Electric<br>Utilities	18
Gas Utilities and<br>Infrastructure	19
Other	21
Consolidated Balance<br>Sheet Highlights	22
Developments	23
Outstanding Stock<br>Data	24
Financial<br>Highlights	25
Florida Electric<br>Utility	25
Canadian Electric<br>Utilities	28
Other Electric<br>Utilities	32
Gas Utilities and<br>Infrastructure	34
Other	38
Liquidity and<br>Capital Resources	41
Consolidated Cash<br>Flow Highlights	42
Working<br>Capital	43
Contractual<br>Obligations	43
Forecasted Gross<br>Consolidated Capital Expenditures	44
Debt<br>Management	45
Credit<br>Ratings	47
Guaranteed<br>Debt	47
Share<br>Capital	48
Pension<br>Funding	48
Off-Balance Sheet Arrangements	49
Dividend Payout<br>Ratio	50
Transactions with<br>Related Parties	50
Enterprise Risk and<br>Risk Management	51
Risk Management<br>including Financial Instruments	63
Disclosure and<br>Internal Controls	65
Critical Accounting<br>Estimates	66
Changes in<br>Accounting Policies and Practices	72
Future Accounting<br>Pronouncements	72
Summary of Quarterly<br>Results	73

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 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; the 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; counterparty risk; disruption of fuel supply; country risks; environmental risks; foreign exchange; 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 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

Emera’s investment in rate-regulated businesses is concentrated in Florida and Nova Scotia. These service areas have generally experienced stable regulatory policies and economic conditions. 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 $8.4 billion over the 2022-to-2024 period (including a $240 million equity investment in the LIL in 2022), with an additional $1 billion of potential capital investments over the same period. This results in a forecasted rate base growth of approximately 7 per cent to 8 per cent through 2024. 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 and at-the-market program. Maintaining investment-grade credit ratings is a priority of management.

•	A 55 per cent reduction in carbon dioxide emissions by 2025.
•	An 80 per cent reduction in coal usage by 2023 and the retirement of Emera’s last existing coal unit no later<br>than 2040.
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•	At least an 80 per cent reduction in carbon dioxide emissions by 2040.
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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

Emera uses financial measures 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 by adjusting certain GAAP measures for specific items the Company believes are significant, but not reflective of underlying operations in the period. These measures are discussed and reconciled below.

Adjusted Net Income Attributable to Common Shareholders, Adjusted Earnings Per Common Share – Basic and Dividend PayoutRatio 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, impacts in 2020 of the gain on sale of Emera Maine, and impairment charges on certain other assets.

The MTM adjustments are a result of the following:

•	MTM adjustments related to Emera’s<br>held-for-trading (“HFT”) commodity derivative instruments, including adjustments related to the price differential between the point where natural gas is<br>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;
•	MTM adjustments included in Emera’s equity income related to the business activities of Bear Swamp Power Company LLC<br>(“Bear Swamp”);
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•	MTM adjustments related to equity securities held in BLPC and Emera Reinsurance, a captive reinsurance company in the Other<br>segment; and
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•	MTM adjustments related to Emera’s foreign exchange cash flow hedges entered to manage foreign exchange earnings<br>exposure.
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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 ongoing operations of the business, and allows investors to better understand and evaluate the business. Management and the Board of Directors exclude these MTM adjustments for evaluation of performance and incentive compensation. For further detail on MTM adjustments, refer to the “Consolidated Financial Review”, “Financial Highlights – Other Electric Utilities”, and “Financial Highlights – Other” 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. For further details, refer to the “Significant Items Affecting Earnings” and “Financial Highlights – Other” sections. While the gain on sale has been excluded from adjusted earnings, earnings for the Other Electric Utilities segment includes earnings from Emera Maine up to the date of its sale on March 24, 2020.

Adjusted earnings per common share – basic and dividend payout ratio of adjusted net income are non-GAAP ratios which are calculated using adjusted net income attributable to common shareholders, 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 and adjusted earnings per common share – basic for the Other Electric Utilities and Other segments. Reconciliation to the nearest GAAP measure is included in each segment. Please refer to “Financial Highlights – Other Electric Utilities” and “Financial Highlights – Other” sections.

The following reconciles reported net income attributable to common shareholders to adjusted net income attributable to common shareholders; and reported earnings per common share – basic, to adjusted earnings per common share – basic:

				Year ended
For the				December 31
millions of Canadian dollars (except per share amounts)	2021		2020	****	2021		2020		2019
Net income attributable to common shareholders	324	$	273	$	510	$	938	$	663
Gain on sale, net of tax and transaction costs (1)	-		-	****	-		309		-
Impairment charges, net of tax (2)	-		-	****	-		(26)		(34)
After-tax MTM gains (losses) (3)	156		85	****	(213)		(10)		76
Adjusted net income attributable to common shareholders	168	$	188	$	723	$	665	$	621
Earnings per common share – basic	1.24	$	1.09	$	1.98	$	3.78	$	2.76
Adjusted earnings per common share – basic	0.64	$	0.75	$	2.81	$	2.68	$	2.59
(1) Net of income tax expense of 276 million for the year ended December 31,<br>2020
(2) Net of income tax expense of 1 million for the year ended December 31, 2020 (2019<br>– nil)
(3) Net of income tax expense of 63 million for the three months ended December 31, 2021 (2020 – 33 million expense) and 86 million recovery for the year ended<br>December 31, 2021 (2020 – 8 million recovery) (2019 – 31 million expense)

All values are in US Dollars.

EBITDA and Adjusted EBITDA

Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) is a non-GAAP financial measure used by Emera. EBITDA is 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.

Adjusted EBITDA is a non-GAAP financial measure used by Emera. Similar to adjusted net income calculations described above, this measure represents EBITDA absent the income effect of Emera’s MTM adjustments, the gain on sale of Emera Maine and impairment charges.

The Company’s EBITDA and Adjusted EBITDA may not be comparable to the EBITDA measures of other companies but, in management’s view, appropriately reflect Emera’s specific operating performance. These measures are not intended to replace “Net income attributable to common shareholders” which, as determined in accordance with GAAP, is an indicator of operating performance.

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

	Three months ended				Year ended
For the	December 31				December 31
millions of Canadian dollars	****	2021		2020	****	2021		2020		2019
Net income (1)	$	338	$	284	$	561	$	984	$	710
Interest expense, net	****	151		159	****	611		679		738
Income tax expense (recovery)	****	85		57	****	(6)		341		61
Depreciation and amortization	****	227		217	****	902		881		903
EBITDA	$	801	$	717	$	2,068	$	2,885	$	2,412
Gain on sale, net of transaction costs (excluding income tax)	****	-		-	****	-		585		-
Impairment charges, excluding income tax	****	-		-	****	-		(25)		(34)
MTM gains (losses), excluding income tax	****	219		118	****	(299)		(18)		107
Adjusted EBITDA	$	582	$	599	$	2,367	$	2,343	$	2,339
(1) Net income is before Non-controlling interest in<br>subsidiaries and Preferred stock dividends.

CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Earnings

Earnings Impact of After-Tax MTM Gains and Losses

After-tax MTM gains increased $71 million to $156 million in Q4 2021, compared to $85 million in Q4 2020, primarily due to settlements and changes in existing positions at Emera Energy. These were partially offset by higher amortization on gas transportation assets in Q4 2021 at Emera Energy and the reversal of 2020 foreign exchange gains on cash flow hedges. For the year ended December 31, 2021, after-tax MTM losses increased $203 million to $213 million compared to $10 million for the same period in 2020 due to changes in existing positions at Emera Energy and the reversal of 2020 foreign exchange gains on cash flow hedges.

2020 TECO Guatemala Holdings (“TGH”) International Arbitration and Award

On November 24, 2020, a payment was made by the Republic of Guatemala in satisfaction of an award issued by the International Centre for the Settlement of Investment Disputes tribunal in 2013. The payment of $49 million ($36 million after tax or $0.15 per common share), net of legal costs was related to a dispute over an investment in a Guatemala local distribution company and was recognized in “Other Income” on the Consolidated Statements of Income. For further detail, refer to note 27 in the consolidated financial statements.

2020 Gainon Sale and Impairment Charges

In addition, impairment charges of $25 million ($26 million after tax) for the year ended December 31, 2020 were recognized on certain other assets.

Consolidated Financial Highlights by Business Segment

For the	Three months ended				Year ended
millions of Canadian dollars		December 31				December 31
Adjusted net income	****	2021		2020	****	2021		2020		2019
Florida Electric Utility	$	85	$	101	$	462	$	501	$	419
Canadian Electric Utilities	****	67		57	****	241		221		229
Other Electric Utilities	****	5		8	****	20		33		76
Gas Utilities and Infrastructure	****	55		45	****	198		162		183
Other	****	(44)		(23)	****	(198)		(252)		(286)
Adjusted net income attributable to common shareholders	$	168	$	188	$	723	$	665	$	621
Gain on sale, net of tax and transaction costs	****	-		-	****	-		309		-
Impairment charges, net of tax	****	-		-	****	-		(26)		(34)
After-tax MTM gains (losses)	****	156		85	****	(213)		(10)		76
Net income attributable to common shareholders	$	324	$	273	$	510	$	938	$	663
The following table highlights the significant changes in adjusted net income attributable to common shareholders from 2020 to 2021:
---	---	---	---	---
For the		Three months ended		Year ended
millions of Canadian dollars		December 31		December 31
Adjusted net income – 2020	$	188	$	665
Operating Unit Performance
Increased earnings at Emera Energy Services (“EES”) due to favourable market conditions		9		37
Increased earnings at PGS due to higher base revenues as a result of a base rate increase on January 1, 2021 and customer growth		10		36
Increased earnings at NSPI due to increased sales volumes quarter-over-quarter. Year-over-year increased due to higher operating revenues, lower interest on the Fuel Adjustment Mechanism (“FAM”) regulatory deferral and<br>decreased income tax expense		7		15
Decreased earnings at Tampa Electric due to higher depreciation and amortization expense, reflecting increased capital investment and a 2020 regulatory settlement, the impact of a stronger CAD and lower base revenue due to weather,<br>partially offset by higher allowance for funds used during construction (“AFUDC”)		(16)		(39)
Decreased earnings due to the sale of Emera Maine in Q1 2020		-		(6)
Tax Related
Revaluation of Corporate, NSPI and Emera Energy net deferred income tax assets and liabilities in Q1 2020 due to the reduction in the Nova Scotia provincial corporate income tax rate		-		14
Recognition of corporate income tax recovery in Q1 2020 previously deferred as a regulatory liability in 2018 at BLPC		-		(10)
Corporate
Decreased interest expense, pre-tax, due to the impact of a stronger CAD and lower interest rates. Year-over-year also due to repayment of corporate debt		6		35
Realized gain on hedges entered into to hedge foreign exchange earnings exposure		2		19
TGH award, net of tax and legal costs in Q4 2020. Refer to the “Significant Items Affecting Earnings” section		(36)		(36)
Other Variances		(2)		(7)
Adjusted net income – 2021	$	168	$	723

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

For the	Year ended December 31
millions of Canadian dollars	****	2021		2020		2019
Operating cash flow before changes in working capital	$	1,337	$	1,420	$	1,598
Change in working capital	****	(152)		217		(73)
Operating cash flow	$	1,185	$	1,637	$	1,525
Investing cash flow	$	(2,332)	$	(1,224)	$	(1,617)
Financing cash flow	$	1,311	$	(372)	$	14
For further discussion of cash flow, refer to the “Consolidated Cash Flow Highlights” section.
As at		December 31
millions of Canadian dollars	****	2021		2020		2019
Total assets	$	34,244	$	31,234	$	31,842
Total long-term debt (including current portion)	$	14,658	$	13,721	$	14,180

Consolidated Income Statement Highlights

For the	Three months ended						Year ended
millions of Canadian dollars		December 31						December 31					December 31
(except per share amounts)	****	2021		2020		Variance	****	2021		2020		Variance	2019
Operating revenues	$	1,868	$	1,537	$	331	$	5,765	$	5,506	$	259		$	6,111
Operating expenses	****	1,352		1,148		(204)	****	4,835		4,359		(476)			4,768
Income from operations	$	516	$	389	$	127	$	930	$	1,147	$	(217)		$	1,343
Income from equity investments	****	32		36		(4)	****	143		149		(6)			154
Other income, net	****	26		75		(49)	****	93		708		(615)			12
Interest expense, net	****	151		159		8	****	611		679		68			738
Income tax expense (recovery)	****	85		57		(28)	****	(6)		341		347			61
Net income	$	338	$	284	$	54	$	561	$	984	$	(423)		$	710
Net income attributable to common shareholders	$	324	$	273	$	51	$	510	$	938	$	(428)		$	663
Gain on sale, net of tax and transaction costs	****	-		-		-	****	-		309		(309)			-
Impairment charges, net of tax	****	-		-		-	****	-		(26)		26			(34)
After-tax MTM gains (losses)	****	156		85		71	****	(213)		(10)		(203)			76
Adjusted net income attributable to common shareholders	$	168	$	188	$	(20)	$	723	$	665	$	58		$	621
Earnings per common share – basic	$	1.24	$	1.09	$	0.15	$	1.98	$	3.78	$	(1.80)		$	2.76
Earnings per common share – diluted	$	1.20	$	1.08	$	0.12	$	1.98	$	3.78	$	(1.80)		$	2.76
Adjusted earnings per common share – basic	$	0.64	$	0.75	$	(0.11)	$	2.81	$	2.68	$	0.13		$	2.59
Dividends per common share declared	$	0.6625	$	0.6375	$	0.0250	$	2.5750	$	2.4750	$	0.1000		$	2.3750
Adjusted EBITDA	$	582	$	599	$	(17)	$	2,367	$	2,343	$	24		$	2,339

Operating Revenues

For the fourth quarter of 2021, operating revenues increased $331 million compared to the fourth quarter in 2020. Absent increased MTM gains of $112 million, operating revenues increased $219 million due to:

•	$97 million increase in the Florida Electric Utility segment due to higher fuel recovery clause revenues as a result<br>of higher fuel costs, partially offset by lower base revenue due to less favourable weather than in Q4 2020 and the impact of a stronger CAD;
•	$82 million increase in the Gas Utilities and Infrastructure segment due to base rate increases at PGS and NMGC<br>effective January 1, 2021, customer growth at PGS, and higher purchased gas adjustment clause revenues at PGS and NMGC as a result of higher gas prices. These increases were partially offset by the impact of a stronger CAD;<br>
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•	$21 million increase in the Other Electric Utilities segment due to higher fuel revenue at BLPC due to higher fuel<br>prices; and
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•	$17 million increase in Other segment due to higher marketing and trading margin at EES, primarily driven by<br>favourable market conditions.
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For the year ended December 31, 2021, operating revenues increased $259 million compared to 2020. Absent increased MTM losses of $241 million, operating revenues increased by $500 million due to:

•	$244 million increase in the Florida Electric Utility segment due to higher fuel recovery clause revenues as a result<br>of higher fuel costs, partially offset by lower base revenue due to less favourable weather than in the prior year and the impact of a stronger CAD;
•	$222 million increase in the Gas Utilities and Infrastructure segment due to base rate increases at PGS and NMGC<br>effective January 1, 2021, customer growth at PGS, and higher purchased gas adjustment clause revenues at PGS and NMGC as a result of higher gas prices. These increases were partially offset by the impact of a stronger CAD; and<br>
---	---
•	$64 million increase in Other segment due to higher marketing and trading margin at EES, primarily driven by<br>favourable market conditions.
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These impacts were partially offset by:

•	$29 million decrease in the Other Electric Utilities segment due to the sale of Emera Maine in Q1 2020.<br>

Operating Expenses

For the fourth quarter of 2021, operating expenses increased $204 million compared to the fourth quarter of 2020. Operating expenses increased due to:

•	$121 million increase in the Florida Electric Utility segment due to higher natural gas prices, partially offset by<br>the impact of a stronger CAD;
•	$73 million increase in the Gas Utilities and Infrastructure segment due to higher gas prices at PGS and NMGC,<br>partially offset by the impact of a stronger CAD; and
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•	$28 million increase in the Other Electric Utilities segment due to higher fuel prices at BLPC.
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For the year ended December 31, 2021, operating expenses increased $476 million compared to 2020. Absent the 2020 impairment charges of $26 million, operating expenses increased $502 million due to:

•	$331 million increase in the Florida Electric Utility segment due to higher natural gas prices, partially offset by<br>the impact of a stronger CAD;
•	$187 million increase in the Gas Utilities and Infrastructure segment due to higher gas prices at PGS and NMGC,<br>partially offset by the impact of a stronger CAD; and
---	---
•	$42 million increase in the Other Electric segment due to higher fuel prices at BLPC.
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These impacts were partially offset by:

•	$48 million decrease in the Other Electric Utilities segment due to the sale of Emera Maine in Q1 2020.<br>

Other Income, Net

Other income, net decreased for Q4 2021 and year ended December 31, 2021, compared to the same periods in 2020, primarily due to the TGH award in Q4 2020. For the year ended December 31, 2021, the decrease was also primarily due to the pre-tax gain on sale of Emera Maine in Q1 2020.

Interest Expense, Net

Interest expense, net was lower for Q4 2021 and year ended December 31, 2021, compared to the same periods in 2020, due to the impact of a stronger CAD and lower interest rates. For the year ended December 31, 2021, the decrease was also due to the repayment of long-term corporate debt.

Income Tax (Recovery) Expense

The increase in income tax expense for Q4 2021, compared to the same period in 2020, was primarily due to increased income before provision for income taxes. The decrease in income tax expense in 2021, compared to 2020, was primarily due to the gain on sale of Emera Maine.

Net Income and Adjusted Net Income

For the fourth quarter of 2021, the decrease in net income attributable to common shareholders, compared to the same period in 2020, was favourably impacted by the $71 million increase in after-tax MTM gains primarily related to Emera Energy. Absent the favourable MTM changes, adjusted net income decreased $20 million. The decrease was primarily due to the TGH award in Q4 2020 and lower earnings at Tampa Electric, partially offset by higher earnings contribution from PGS, EES, and NSPI.

For the year ended December 31, 2021, net income attributable to common shareholders, compared to the same period in 2020, was unfavourably impacted by the $309 million after-tax gain on sale of Emera Maine in 2020, unfavourably impacted by the $203 million increase in after-tax MTM losses primarily related to Emera Energy, and favourably impacted by the $26 million after-tax impairment charge in 2020. Absent the net gain on sale of Emera Maine in 2020, the unfavourable MTM changes and the 2020 impairment charges, adjusted net income increased $58 million. The increase was primarily due to higher earnings contribution from EES, PGS and NSPI, lower corporate interest expense, realized gains on foreign exchange hedges and the 2020 revaluation of deferred taxes due to a reduction in the Nova Scotia corporate income tax rate. The increase was partially offset by the TGH award in Q4 2020, the impact of a stronger CAD, and the 2020 recognition of a corporate income tax recovery previously deferred as a regulatory liability in 2018 at BLPC.

Earnings and Adjusted Earnings per Common Share – Basic

Earnings per common share – basic were higher for Q4 2021, compared to Q4 2020 due to increased earnings as discussed above, partially offset by the impact of the increase in weighted average shares outstanding. Adjusted earnings per common share – basic were lower for Q4 2021 compared to Q4 2020 due to decreased earnings as discussed above, and the impact of the increase in weighted average shares outstanding.

Earnings per common share – basic for the year ended December 31, 2021 decreased compared to 2020 due to the decreased earnings as discussed above, and the impact of the increase in weighted average shares outstanding. Adjusted earnings per common share were higher for the year ended December 31, 2021, compared to 2020, due to increased adjusted earnings as discussed above, partially offset by the impact of the increase in weighted average shares outstanding.

Effect of Foreign Currency Translation

Emera operates internationally including in Canada, the US and various Caribbean countries. As such, the Company 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 of foreign exchange in any period is driven by rate changes, the timing of earnings from foreign operations during the period, the percentage of earnings from foreign operations in the period and the impact of entered foreign exchange cash flow hedges to manage foreign exchange 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 2021 and 2020 are as follows:

	Three months ended				Year ended
	December 31				December 31
	2021		2020		2021		2020
Weighted average CAD/USD	$	1.26	$	1.30	$	1.26	$	1.34
Period end CAD/USD exchange rate	$	1.27	$	1.27	$	1.27	$	1.27

Strengthening of the CAD decreased net income by $10 million and decreased adjusted net income by $1 million in Q4 2021, compared to Q4 2020. The strengthening of the CAD decreased net income by $17 million and adjusted net income by $28 million for the year ended December 31, 2021, compared to 2020.

Consistent with the Company’s risk management policies, Emera partially manages currency risks through matching US denominated debt to finance its US operations and uses foreign currency derivative instruments to hedge specific transactions and earnings exposure. Emera does not utilize derivative financial instruments for foreign currency trading or speculative purposes.

The table below includes Emera’s significant segments whose contributions to adjusted earnings are recorded in USD currency.

	Three months ended					Year ended
For the	December 31					December 31
millions of US dollars	2021			2020		2021			2020
Florida Electric Utility	$	67	****	$	76	$	369	****	$	372
Other Electric Utilities	****	4	****		5	****	16	****		24
Gas Utilities and Infrastructure (1)	****	37	****		30	****	130	****		97
Other segment (2)	****	(20	)		5	****	(98	)		(102	)
Total (3)	$	88	****	$	116	$	417	****	$	391

(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) Net of $122 million in after-tax MTM gain for the three months ended December 31, 2021 (2020 – $62 million after-tax MTM gain) and after-tax MTM loss of $164 million for the year ended December 31, 2021 (2020 – $11 million after-tax MTM loss, and $212 million gain on sale of Emera Maine, net of tax and transaction costs).

BUSINESS OVERVIEW AND OUTLOOK

COVID-19 Pandemic

Potential future impacts of COVID-19 on the business may include the following:

•	Lower earnings as a result of lower sales volumes due to economic slowdowns and the pace and strength of economic recovery;<br>
•	Delays of capital projects as a result of construction shutdowns, government restrictions on<br>non-essential capital work, travel restrictions for contractors or supply chain disruptions;
---	---
•	Deferral of and adjustment to regulatory filings, hearings, decisions and recovery periods; and
---	---
•	Decreased cash flow from operations due to lower earnings and slower collection of accounts receivable or increased credit<br>losses.
---	---

Refer to the outlook sections by segment below, for affiliate specific impacts, if applicable.

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 $10.7 billion USD of assets and approximately 810,600 customers at December 31, 2021. Tampa Electric owns 5,919 MW of generating capacity, of which 77 per cent is natural gas-fired, 12 per cent is solar and 11 per cent is coal. Tampa Electric owns 2,165 kilometres of transmission facilities and 19,530 kilometres of distribution facilities.

Tampa Electric anticipates earning within its ROE range in 2022. New base rates effective January 1, 2022 will result in higher 2022 USD earnings than in 2021. Tampa Electric sales volumes are expected to be similar to 2021, which benefited from weather that was warmer than normal (a 20-year statistical degree day average). Tampa Electric expects customer growth rates in 2022 to be consistent with 2021, reflective of current expected economic growth in Florida.

On August 6, 2021, Tampa Electric filed with the FPSC a joint motion for approval of a settlement agreement (the “Settlement Agreement”) by Tampa Electric and the intervenors in relation to its rate case filed with the FPSC in April 2021. The Settlement Agreement provides for a projected increase of $191 million USD in rates annually, effective with January 2022 bills. This increase will consist of $123 million USD in base rate charges and $68 million USD to recover the costs of retiring assets including, Big Bend coal generation assets Units 1 through 3 and meter assets. The Settlement Agreement further includes two subsequent year adjustments of $90 million USD and $21 million USD, effective January 2023 and January 2024, respectively related to the recovery of future investments in the Big Bend Modernization project and solar generation. The allowed equity in the capital structure will continue to be 54 per cent from investor sources of capital. The Settlement Agreement includes an allowed regulated ROE range of 9.0 per cent to 11.0 per cent with a 9.95 per cent midpoint. It also provides for a 25 basis point increase in the allowed ROE range and mid-point, and $10 million USD of additional revenue, if U.S. Treasury Bond yields exceed a specific threshold set on the date the FPSC votes to approve the agreement. Under the agreement, base rates will not further change from January 1, 2022 through December 31, 2024, unless Tampa Electric’s earned ROE were to fall below the bottom of the range during that time. The Settlement Agreement contains a provision whereby Tampa Electric agrees to quantify the future impact of a change in tax rates on net operating income through a reduction or increase in base revenues within 180 days of when such tax change becomes law or its effective date. The Settlement Agreement further creates a mechanism to recover the costs of retiring coal generation units and meter assets over a period of 15 years which survives the term of that agreement. The Settlement Agreement sets new depreciation and dismantlement rates effective January 1, 2022 and contains the provisions that Tampa Electric will not have to file another depreciation study during the term of the agreement but will file a new depreciation study no more than one year, nor less than 90 days, before the filing of its next general base rate proceeding. Tampa Electric agreed not to hedge natural gas through the period ending on December 31, 2024. On October 21, 2021, the FPSC approved the Settlement Agreement and the final order, reflecting such approval, was issued in November 2021.

In 2022, capital investment in the Florida Electric Utility segment is expected to be $1.1 billion USD (2021 - $1.2 billion USD), including AFUDC. Capital projects include continuation of the modernization of the Big Bend Power Station, 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 $6.1 billion of assets and approximately 536,000 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 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. Due to continued rate base growth, NSPI anticipates earning within its allowed ROE range in 2022 and expects earnings to be consistent with 2021. Warmer than normal weather adversely affected NSPI’s sales volumes in 2021. Assuming normal weather in 2022, NSPI expects sales volumes to be higher than 2021.

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 reductions will be recoverable under NSPI’s regulatory framework.

In Q1 2021, NSPI received its 2021 granted emissions allowances under the Nova Scotia Cap-and-Trade Program Regulations. These 2021 allowances will be used in 2021 or allocated within the initial four-year compliance period that ends in 2022. In addition to the granted allowances, NSPI 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. Reserve credits are anticipated to be priced at a premium to provincial auction pricing. Compliance is forecast to be achieved through granted emissions allowances, reduced emissions partly due to delivery of energy from Muskrat Falls, and credit purchases under the Cap-and-Trade Program, including reserve credits. NSPI anticipates that any prudently incurred costs required to comply with the Government of Canada’s laws and regulations, and the Nova Scotia Cap-and-Trade Program Regulations, will be recoverable under NSPI’s regulatory framework.

Energy from renewable sources has increased with Nalcor Energy’s (“Nalcor”) NS Block delivery obligations from the Muskrat Falls hydroelectric project (“Muskrat Falls”) commencing August 15, 2021. Nalcor will provide NSPI with approximately 900 GWh of energy annually over 35 years. In addition, for the first five years of the NS Block, NSPI is also entitled to receive approximately 240 GWh of additional energy from the Supplemental Energy Block transmitted through the Maritime Link. As Nalcor is in the final stages of commissioning the LIL, there will be periodic commissioning related interruptions in supply with any resultant delivery shortfalls being delivered at a date to be agreed to by the companies. Commencing in September 2022, NSPI has the option of purchasing additional market-priced energy from Nalcor through the Energy Access Agreement. Pursuant to the Energy Access Agreement, Nalcor is obligated to offer NSPI a minimum average of 1.2 TWh of energy annually. Nalcor is forecasting it will achieve final commissioning of the Lower Churchill projects (including Muskrat Falls and LIL) in the first half of 2022.

On November 5, 2021, the provincial government enacted Bill 57, “Environmental Goals and Climate Change Reduction Act,” which signals the provincial government’s intent to implement several climate change related goals and greenhouse gas reduction targets, many of which overlap with and replace provisions of pre-existing acts. The legislation also introduces a goal to phase out coal-fired electricity generation in Nova Scotia by 2030. Subsequent provincial regulations will be required to detail how these goals and targets will be achieved.

On July 9, 2021, the provincial government amended the Renewable Electricity Regulations, mandating that 80 per cent of electric sales be generated from renewable sources by 2030.

On June 29, 2021, the federal government enacted Bill C-12 “Canadian Net-Zero Emissions Accountability Act” with the objective of attaining net-zero emissions by 2050.

In 2022, NSPI expects to invest $530 million (2021 – $388 million), including AFUDC, primarily in capital projects to support system reliability, renew hydroelectric infrastructure, and increase renewable energy.

ENL

Total equity earnings from NSPML and LIL are expected to be higher in 2022, compared to 2021. Both the NSPML and LIL investments are recorded as “Investments subject to significant influence” on Emera’s Consolidated Balance Sheets.

NSPML

NSPML received UARB approval to collect up to $172 million (2020 – $145 million) from NSPI for the recovery of costs associated with the Maritime Link in 2021. This was subject to a holdback of up to $10 million that was dependent upon the timing of commencement of the NS Block. On January 18, 2022, the UARB directed NSPI to pay to NSPML approximately $10 million of the 2021 holdback. NSPML has deferred collection and recognition of $23 million in depreciation expense. Approximately $162 million is included in NSPI rates in 2022.

On August 9, 2021, NSPML filed a final capital cost application with the UARB, seeking approval to recover capital costs associated with the Maritime Link and approval of NSPML’s 2022 assessment. In December 2021, NSPML obtained an interim decision from the UARB approving interim rates beginning January 1, 2022, until receipt of the UARB’s decision on the application. On February 9, 2022, the UARB issued its decision relating to the Maritime Link Project, approving NSPML’s requested rate base of approximately $1.8 billion less costs that would not otherwise have been recoverable if incurred by NSPI. The UARB also approved approximately $168 million of NSPML revenue requirement in 2022 subject to a holdback of $2 million per month beginning April 1, 2022 and thereafter to the end of the year. This holdback is to be used to fund any replacement energy costs incurred by NSPI due to a 10 per cent or greater shortfall in contracted NS Block deliveries each month and will otherwise be released to NSPML. NSPML is required to provide the UARB with a compliance filing by February 16, 2022 which will confirm the impacts of this decision including the amount of the unrecoverable items which are not expected to exceed $10 million (pre-tax).

In 2022, NSPML expects to invest approximately $5 million (2021 – $6 million) in capital.

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 the first half of 2022.

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, a 51.9 per cent interest in Domlec on the island of Dominica 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 24, 2020, Emera completed the sale of Emera Maine which is included in the Other Electric Utilities segment for Q1 2020.

BLPC

With $489 million USD of assets and approximately 132,000 customers, BLPC owns 266 MW of generating capacity, of which 96 per cent is oil-fired and four per cent is solar. The utility has an additional 12 MW of capacity from rental units. BLPC owns approximately 188 kilometres of transmission facilities and 3,800 kilometres of distribution facilities. BLPC’s approved regulated return on rate base is 10.0 per cent.

GBPC

With $349 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. Restoration of the generating units damaged by Hurricane Dorian was completed in 2021. GBPC’s approved regulatory return on rate base for 2022 is 8.23 per cent (2021 – 8.37 per cent). See below for further details.

Domlec

Domlec serves approximately 35,700 customers. Domlec owns 26.7 MW of generating capacity, of which 75 per cent is oil-fired and 25 per cent is hydro. Domlec owns approximately 475 kilometres of transmission facilities and 709 kilometres of distribution facilities. Domlec’s approved regulated return on rate base is 15.0 per cent.

Other Electric Utilities Outlook

Other Electric Utilities’ USD earnings in 2022 are expected to increase over the prior year due to higher earnings due to higher base rates at GBPC and BLPC and the continued recovery in local economies from the impacts of COVID-19.

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. Following a general election called late in 2021 for January 19, 2022, the new licenses are expected to take effect in 2022 on completion of the legislative process. The Dispatch license will have 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 currently assessing the full impact of the new licenses on its business and working towards the successful implementation of the licenses.

On October 4, 2021 BLPC submitted a general rate review application to the FTC. The application seeks a rate adjustment and the implementation of a cost reflective rate structure that will facilitate the changes expected in the newly reformed electricity market and the country’s transition towards 100 per cent renewable energy generation. The application seeks recovery of capital investment in plant, equipment and related infrastructure and results in an increase in annual non-fuel revenue of approximately $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. A decision is expected from the FTC in the second half of 2022.

On January 14, 2022, the GBPA issued its decision on GBPC’s application for rate review that was filed with the GBPA on September 23, 2021. The decision, which becomes effective April 1, 2022, allows for an increase in revenues of $3.5 million USD. The new rates include a regulatory ROE of 12.84 per cent.

In 2022, capital investment in the Other Electric Utilities segment is expected to be $100 million USD (2021 – $88 million USD), primarily in more efficient and cleaner sources of generation, including renewables and battery storage.

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 $2.2 billion USD of assets and approximately 445,000 customers, the PGS system includes 23,150 kilometres of natural gas mains and 13,100 kilometres of service lines. Natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) was 1.9 billion therms in 2021.

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 $1.7 billion USD of assets and approximately 542,000 customers, NMGC serves approximately 60 per cent of New Mexico’s population in 24 of the state’s 33 counties. NMGC’s system includes approximately 2,424 kilometres of transmission pipelines and 17,593 kilometres of distribution pipelines. Annual natural gas throughput was approximately 839 million therms in 2021.

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 2022 than 2021, primarily due to rate base growth to expand the distribution system and to continue to reliably serve customers. The PGS rate case settlement provides the ability to reverse a total of $34 million USD of accumulated depreciation through 2023. PGS has not reversed any of this accumulated depreciation to date. The reversal of accumulated depreciation is expected to occur over the 2022 and 2023 periods.

PGS anticipates earning within its allowed ROE range in 2022 and expects rate base and USD earnings to be higher than in 2021. PGS expects favourable customer growth in 2022 (following Florida’s population growth and housing demands), PGS sales volumes in 2022 are expected to increase at a level consistent with customer growth.

NMGC anticipates earning near its authorized ROE in 2022 and expects rate base to be higher than 2021. NMGC expects customer growth rates to be consistent with historical trends.

On December 13, 2021, NMGC filed a rate case with the NMPRC for new rates to become effective January 2023. NMGC requested a $41 million USD increase in annual base revenues primarily as a result of increased operating costs and capital investments in pipelines and related infrastructure. A decision from the NMPRC is expected by the end of 2022.

In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in an incremental $108 million USD for gas costs above what it would normally have paid during this period. NMGC normally recovers gas supply and related costs through a purchased gas adjustment clause. On April 16, 2021, NMGC filed a Motion for Extraordinary Relief, as permitted by the NMPRC rules, to extend the terms of the repayment of the incremental gas costs and to recover a carrying charge. On June 15, 2021 the NMPRC approved the recovery of $108 million USD and related borrowing costs over a period of 30 months beginning July 1, 2021.

In 2018, SeaCoast executed an agreement with Seminole Electric Cooperative, Inc. (“Seminole”) to provide long-term firm gas transportation service to Seminole’s new gas-fired generating facility being constructed in Putnam County, Florida. SeaCoast will operate a 21-mile, 30-inch pipeline lateral that will be treated as a sales-type lease for accounting purposes. The lease of the pipeline lateral to Seminole will commence in 2022. The capital investment is approximately $100 million USD, with the majority of the project investment completed through 2021.

In 2022, capital investment in the Gas Utilities and Infrastructure segment is expected to be approximately $445 million USD (2021 - $407 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

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 50.0 per cent joint venture ownership of Bear Swamp, a 633 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.

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).

The adjusted net loss from the Other segment is expected to be higher in 2022, based on EES returning to its normal earnings range in 2022, higher operating, maintenance and general (“OM&G”) expenses, lower realized foreign exchange gains on cash flow hedges and increased interest expense. The decrease is expected to be partially offset by decreased taxes due to a higher net loss.

In 2022, capital investment in the Other segment is expected to be $2 million (2021 – $1 million).

CONSOLIDATED BALANCE SHEET HIGHLIGHTS

Significant changes in the Consolidated Balance Sheets between December 31, 2020 and December 31, 2021 include:

millions of Canadian dollars	Increase<br>(Decrease)	Explanation
Assets
Cash and cash equivalents	$ 174	Increased due to cash from operations, net issuances of debt at TEC, NMGC and GBPC, and issuance of preferred and common stock. This was partially offset by investments in property, plant and<br>equipment and dividends on common stock.
Inventory	85	Increased due to higher commodity prices at Emera Energy, and higher fuel inventory and materials inventory at NSPI.
Derivative instruments (current and long-term)	203	Increased due to higher commodity prices and new derivative contracts, partially offset by settlements at NSPI.
Regulatory assets (current and long-term)	982	Increased due to the Tampa Electric capital cost recovery for early retired assets, increased deferrals related to the FAM and increased deferred income tax regulatory assets at NSPI, and the<br>NMGC winter event gas cost recovery. These were partially offset by decreased pension and post-retirement plan deferrals at Tampa and PGS.
Receivables and other assets (current and long-term)	674	Increased due to higher cash collateral and trade receivables due to higher commodity prices and increased gas transportation assets at Emera Energy and higher pension and post-retirement<br>assets at TEC and NSPI.
Property, plant and equipment, net of accumulated depreciation and amortization	818	Increased due to additions at Tampa Electric, PGS and NSPI, partially offset by the reclassification related to the Tampa Electric capital cost recovery for early retired assets.
Liabilities and Equity
Short-term debt and long-term debt (including current portion)	$ 1,054	Increased due to issuances of long-term debt at TEC, NMGC and GBPC and net issuance on committed credit facilities at TEC, NSPI and Corporate. These were partially offset by repayment of debt<br>at TEC.
Accounts payable	337	Increased due to higher commodity prices at Emera Energy, higher natural gas prices at Tampa Electric, and increased cash collateral positions on derivative instruments at NSPI.
Deferred income tax liabilities, net of deferred income tax assets	153	Increased due to tax deductions in excess of accounting depreciation related to property, plant and equipment.
Derivative instruments (current and long-term)	344	Increased due to new contracts in 2021 and changes in existing positions, partially offset by reversal of 2020 contracts at Emera Energy.
Regulatory liabilities (current and long-term)	94	Increased due to deferrals related to derivative instruments at NSPI, partially offset by decreased deferred income tax regulatory liabilities, primarily due to amortization of excess deferred<br>income taxes related to US Tax Reform at Tampa Electric, PGS and NMGC.
Pension and post-retirement liabilities	(83)	Decreased due to favourable changes in actuarial assumptions and higher investment returns on pension plan assets at NSPI.
Other liabilities (current and long-term)	113	Increased due to investment tax credits related to solar projects at Tampa Electric and emissions compliance charges at NSPI.
Common stock	537	Increased due to shares issued under Emera’s at-the-market equity program and the dividend reinvestment<br>plan.
Cumulative preferred stock	418	Increased due to issuances of preferred shares.
Accumulated other comprehensive income	104	Decrease in unrecognized pension and post-retirement benefit costs due to favourable changes in actuarial assumptions, higher than anticipated investment returns and amortization at NSPI,<br>partially offset by the effect of a stronger CAD on the translation of Emera’s foreign affiliates.
Retained earnings	(147)	Decreased due to dividends paid in excess of net income.

DEVELOPMENTS

Increasein Common Dividends

On September 24, 2021, the Emera Board of Directors approved an increase in the annual common share dividend rate to $2.65 from $2.55. The first payment was effective November 15, 2021. Emera also extended its dividend growth rate target of four to five per cent through 2024.

TampaElectric Rate Case Settlement Agreement

On August 6, 2021, Tampa Electric filed with the FPSC a joint motion for approval of a Settlement Agreement by Tampa Electric and the intervenors in relation to its rate case filed with the FPSC in April 2021. The Settlement Agreement provides for a projected increase of $191 million USD in rates annually, effective with January 2022 bills. This increase will consist of $123 million USD in base rate charges and $68 million USD to recover the costs of retiring assets including Big Bend coal generation assets Units 1 through 3 and meter assets. The Settlement Agreement further includes two subsequent year adjustments of $90 million USD and $21 million USD, effective January 2023 and January 2024, respectively related to the recovery of future investments in the Big Bend Modernization project and solar generation. The allowed equity in the capital structure will continue to be 54 per cent from investor sources of capital. The Settlement Agreement includes an allowed regulated ROE range of 9.0 per cent to 11.0 per cent with a 9.95 per cent midpoint. On October 21, 2021, the FPSC approved the settlement agreement, and the final order reflecting such approval, was issued on November 10, 2021. For further information, refer to the “Business Overview and Outlook – Florida Electric Utility” section.

Delivery of NS Block

Nalcor’s NS Block delivery obligations commenced on August 15, 2021, and delivery will continue 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 at a date to be agreed to by the companies**.** On August 9, 2021, NSPML filed a final capital cost application with the UARB seeking approval to recover capital costs associated with the Maritime Link and approval of NSPML’s 2022 assessment. In December 2021, NSPML obtained an interim decision from the UARB approving interim rates beginning January 1, 2022, until receipt of the UARB’s decision on the application. On February 9, 2022, the UARB issued its decision relating to the Maritime Link Project, approving NSPML’s requested rate base of approximately $1.8 billion less costs that would not otherwise have been recoverable if incurred by NSPI. For further information on the NS Block and the UARB decision, refer to the “Business Overview and Outlook – Canadian Electric Utilities” and “Contractual Obligations” sections.

Preferred Shares

On September 24, 2021, Emera issued 9 million Cumulative Redeemable First Preferred Shares, Series L at $25.00 per share at an annual yield of 4.60 per cent. The aggregate gross and net proceeds from the offering were $225 million and $222 million, respectively. The net proceeds of the preferred share offering were used for general corporate purposes.

On April 6, 2021, Emera issued 8 million Cumulative Minimum Rate Reset First Preferred Shares, Series J at $25.00 per share at an initial dividend rate of 4.25 per cent. The aggregate gross and net proceeds from the offering were $200 million and $196 million, respectively. The net proceeds of the preferred share offering were used for general corporate purposes.

Appointments

Board ofDirectors

Effective February 11, 2022, Paula Y. Gold-Williams joined the Emera Board of Directors. Ms. Gold-Williams is the former president and CEO of CPS Energy, the largest municipally-owned energy utility in the U.S., serving the city of San Antonio, Texas.

Effective February 11, 2022, Ian E. Robertson joined the Emera Board of Directors. Mr. Robertson is Chief Executive Officer of the Northern Genesis group of special purpose acquisition companies focused on identifying and acquiring energy transition businesses which demonstrate strong sustainability and Environmental, Social and Governance (“ESG”) alignment. He is the former CEO of Algonquin Power & Utilities Corp., a publicly traded, diversified international generation, transmission, and distribution utility.

Effective August 10, 2021, Gil C. Quiniones joined the Emera Board of Directors. Mr. Quiniones is the former President and Chief Executive Officer of the New York Power Authority. Effective October 13, 2021, Mr. Quiniones resigned from the Emera Board of Directors following an appointment to a new senior executive position at a different organization.

Executive

On September 14, 2021, Emera announced that Helen Wesley was appointed President of PGS effective December 1, 2021. Ms. Wesley was most recently the Chief Operating Officer at PGS and succeeds T.J. Szelistowski who retired in December 2021.

OUTSTANDING STOCK DATA

Common stock
	millions of		millions of
Issued and outstanding:	shares		Canadian dollars
Balance, December 31, 2019		242.48		$	6,216
Issuance of common stock (1)		4.54			251
Issued for cash under Purchase Plans at market rate		3.99			219
Discount on shares purchased under Dividend Reinvestment Plan		-			(4	)
Options exercised under senior management stock option plan		0.42			20
Employee Share Purchase Plan		-			3
Balance, December 31, 2020		251.43		$	6,705
Issuance of common stock (2)		4.99			284
Issued for cash under Purchase Plans at market rate		4.32			239
Discount on shares purchased under Dividend Reinvestment Plan		-			(4	)
Options exercised under senior management stock option plan		0.33			14
Employee Share Purchase Plan		-			4
Balance, December 31, 2021	****	261.07		$	7,242	****

(1) As at December 31, 2020, 4,544,025 common shares were issued under Emera’s at-the-market program (“ATM program”) at an average price of $56.04 per share for gross proceeds of $255 million ($251 million net of issuance costs).

(2) In Q4 2021, 1,247,300 common shares were issued under Emera’s ATM program at an average price of $59.89 per share for gross proceeds of $74 million ($73 million net of after-tax issuance costs). For the year ended December 31, 2021, 4,987,123 common shares were issued under Emera’s ATM program at an average price of $57.63 per share for gross proceeds of $287 million ($284 million net of after-tax issuance costs). As at December 31, 2021, an aggregate gross sales limit of $457 million remained available for issuance under the ATM program.

As at February 8, 2022, the amount of issued and outstanding common shares was 261.2 million.

The weighted average shares of common stock outstanding – basic, which includes both issued and outstanding common stock and outstanding deferred share units, for the three months ended December 31, 2021 was 260.8 million (2020 – 251.3 million). The weighted average shares of common stock outstanding – basic for the year ended December 31, 2021 was 257.2 million (2020 – 247.8 million).

ATM Equity Program

FINANCIAL HIGHLIGHTS

Florida Electric Utility

All amounts are reported in USD, unless otherwise stated.

For the		Three months ended<br> <br>December 31				Year ended<br> <br>December 31
millions of US dollars (except per share amounts)	****	2021		2020	****	2021		2020
Operating revenues – regulated electric	$	561	$	468	$	2,174	$	1,849
Regulated fuel for generation and purchased power	$	212	$	127	$	713	$	428
Contribution to consolidated net income	$	67	$	76	$	369	$	372
Contribution to consolidated net income – CAD	$	85	$	101	$	462	$	501
Contribution to consolidated earnings per common share – basic – CAD	$	0.33	$	0.40	$	1.80	$	2.02
Net income weighted average foreign exchange rate – CAD/USD	$	1.25	$	1.31	$	1.25	$	1.34

Net Income

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

For the<br><br><br>millions of US dollars	Three months ended December 31		Year ended<br> <br>December 31
Contribution to consolidated net income – 2020	76	$	372
Increased operating revenues - see Operating Revenues - Regulated Electric<br>below	92		324
Increased fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power below	(85		(285	)
Increased OM&G expenses due to the timing of deferred clause recoveries, increased general consulting costs and higher insurance costs	(11		(15	)
Increased depreciation and amortization due to increase property, plant and equipment and a 2020 regulatory settlement	(7		(35	)
Increased AFUDC earnings due to the Big Bend Power Station modernization and solar projects	4		15
Other	(2		(7	)
Contribution to consolidated net income – 2021	67	$	369	****

All values are in US Dollars.

Florida Electric Utility’s CAD contribution to consolidated net income decreased $16 million in Q4 2021, compared to Q4 2020, and decreased $39 million in 2021, compared to 2020. Decreases in both periods were due to higher depreciation and amortization expense, reflecting increased capital investment and a 2020 regulatory settlement, the impact of a stronger CAD, and lower base revenue, partially offset by higher AFUDC earnings.

The impact of the change in the foreign exchange rate decreased CAD earnings for the quarter and year ended December 31, 2021 by $4 million and $34 million, respectively.

Operating Revenues – Regulated Electric

Electric revenues increased $93 million to $561 million in Q4 2021, compared to $468 million in Q4 2020, and increased $325 million to $2,174 million in 2021, compared to $1,849 million in 2020. Increases in both periods were due to higher fuel recovery clause revenue as a result of higher fuel costs, partially offset by lower base revenues resulting from less favourable weather compared to 2020.

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

Q4 Electric Revenues
millions of US dollars
	2021		2020
Residential	$	289	$	256
Commercial	****	163		132
Industrial	****	48		34
Other (1)	****	61		46
Total	$	561	$	468

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

Q4 Electric Sales Volumes

Gigawatt hours (“GWh”)
	2021		2020
Residential	****	2,312		2,465
Commercial	****	1,525		1,526
Industrial	****	537		460
Other	****	501		515
Total	****	4,875		4,966

Annual Electric Revenues

millions of US dollars
	2021		2020
Residential	$	1,156	$	1,018
Commercial	****	602		506
Industrial	****	172		133
Other (1)	****	244		192
Total	$	2,174	$	1,849

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

Annual Electric Sales Volumes

GWh
	2021		2020
Residential	****	9,941		10,122
Commercial	****	6,144		6,058
Industrial	****	2,122		1,891
Other	****	2,000		1,958
Total	****	20,207		20,029

Regulated Fuel for Generation and Purchased Power

Tampa Electric is required to maintain a generating capacity greater than firm peak demand. The total Tampa Electric-owned generation capacity at December 31, 2021 is 5,919 MW. 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.

Regulated fuel for generation and purchased power increased $85 million to $212 million in Q4 2021, compared to $127 million in Q4 2020, and increased $285 million to $713 million in 2021, compared to $428 million in 2020. The increases in both periods were primarily due to increased natural gas prices.

Q4 Production Volumes

GWh ****
	2021		2020
Natural gas	****	4,130		3,616
Coal	****	64		344
Solar	****	255		232
Purchased power	****	377		747
Total	****	4,826		4,939
Q4 Average Fuel Costs
US dollars	2021		2020
Dollars per Megawatt hour (“MWh”)	$	44	$	26

Annual Production Volumes

GWh ****
	2021		2020
Natural gas	****	16,142		16,523
Coal	****	1,342		904
Solar	****	1,252		1,120
Purchased power	****	2,301		2,513
Total	****	21,037		21,060
Annual Average Fuel Costs
US dollars	2021		2020
Dollars per MWh	$	34	$	20

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.

Average fuel cost per MWh increased in Q4 2021 and for the year ended December 31, 2021, compared to the same periods 2020, primarily due to increased natural gas prices.

Regulatory Recovery Mechanisms

Tampa Electric is regulated by 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.

Solar Base Rate Adjustments Included in Base Rates

As of December 31, 2021, Tampa Electric has invested $850 million in 600 MW of utility-scale solar photovoltaic projects, which are recoverable through FPSC-approved solar base rate adjustments (“SoBRAs”). AFUDC was earned on these projects during construction. The FPSC has approved SoBRAs representing a total of 600 MW, or $104 million annually in estimated revenue requirements for in-service projects.

The true-up filing for SoBRAs tranche 1 and 2 revenue requirement estimates which were included in base rates as of September 2018 and January 2019, respectively, was submitted on April 30, 2020, and the FPSC approved the amount on August 18, 2020. A $5 million true-up was returned to customers in 2020. The true-up filing for SoBRA tranche 3, included in base rates as of January 2020, was approved by the FPSC on October 12, 2021. An estimated $4 million true-up was returned to customers during 2021. The true-up for SoBRA tranche 4 will be filed in early 2022.

Other Cost Recovery

Fuel Recovery Clause

Storm Protection Plan Cost Recovery Clause

Other Cost Recovery Clauses

The FPSC annually approves cost-recovery rates for purchased power, capacity, environmental and conservation costs including a return on capital invested. Differences between prudently incurred clause-recoverable costs and amounts recovered from customers through electricity rates in a year are deferred to a corresponding regulatory asset or liability and recovered from or returned to customers in a subsequent year.

Storm Reserve

Capital Cost Recovery for Early Retired Assets

This regulatory asset is related to the remaining net book value of Big Bend Power Station Units 1 through 3 and smart meter assets that were retired. The balance earns a rate of return as permitted by the FPSC and will be recovered as a separate line item on customer bills for a period of 15 years. This recovery mechanism is authorized by and survives the term of the settlement agreement approved by the FPSC in 2021.

Canadian Electric Utilities

		Three months ended				Year ended
For the		December 31				December 31
millions of Canadian dollars (except per share amounts)	****	2021		2020	****	2021		2020
Operating revenues – regulated electric	$	389	$	377	$	1,501	$	1,494
Regulated fuel for generation and purchased power (1)	$	263	$	219	$	817	$	721
Income from equity investments	$	25	$	21	$	103	$	96
Contribution to consolidated net income	$	67	$	57	$	241	$	221
Contribution to consolidated earnings per common share – basic	$	0.26	$	0.23	$	0.94	$	0.89

(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 net income is summarized in the following table:

		Three months ended				Year ended
For the		December 31				December 31
millions of Canadian dollars	****	2021		2020	****	2021		2020
NSPI	$	43	$	36	$	141	$	125
Equity investment in LIL	****	14		12	****	51		49
Equity investment in NSPML	****	10		9	****	49		47
Contribution to consolidated net income	$	67	$	57	$	241	$	221

Net Income

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

For the	Three months ended					Year ended
millions of Canadian dollars	December 31					December 31
Contribution to consolidated net income – 2020		$	57	****	$	221	****
Increased operating revenues - see Operating Revenues – Regulated Electric below			12			7
Increased fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power below			(44	)		(96	)
Decreased FAM expense and fixed cost deferrals due to under-recovery of current period fuel costs compared to prior year’s over-recovery of fuel costs, partially offset by the refund to customers in 2020 of prior years’<br>fuel costs			40			101
Increased depreciation and amortization year-over-year due to increased property, plant and equipment			(1	)		(10	)
Decreased interest expense, net due to lower interest on the FAM regulatory deferral			1			7
Increased income tax expense quarter-over-quarter primarily due to increased income before provision for income taxes. Decreased income tax expense year-over-year primarily due to increased tax deductions in excess of accounting<br>depreciation related to property, plant and equipment, partially offset by increased income before provision for income taxes.			(2	)		7
Other			4			4
Contribution to consolidated net income – 2021		$	67	****	$	241	****

Canadian Electric Utilities’ contribution to consolidated net income increased $10 million to $67 million in Q4 2021, compared to $57 million in Q4 2020, and increased $20 million to $241 million in 2021 compared to $221 million in 2020. Increases in both periods were primarily driven by higher contribution from NSPI. Quarter-over-quarter, the increase was primarily due to increased sales volumes. Year-over-year, the increase was primarily due to higher operating revenues, lower interest costs, and decreased income tax expense primarily due to tax deductions in excess of accounting depreciation related to property, plant and equipment. Increases were partially offset by higher depreciation and amortization.

The timing of regulatory deferrals causes quarterly earnings volatility, while full year results are more predictable.

NSPI

Operating Revenues – Regulated Electric

Operating revenues increased $12 million to $389 million in Q4 2021, compared to $377 million in Q4 2020 due to increased sales volume due to colder weather, fuel-related pricing, and increased customer sales volume, partially offset by lower Maritime Link assessment included in revenue compared to Q4 2020.

For the year ended December 31, 2021, operating revenues increased $7 million to $1,501 million, compared to $1,494 million in 2020 due to increased customer sales volume growth and fuel-related pricing, partially offset by lower Maritime Link assessment included in revenue compared to 2020.

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

Q4 Electric Revenues
millions of Canadian dollars
	2021		2020
Residential	$	209	$	199
Commercial	****	104		102
Industrial	****	61		60
Other	****	6		7
Total	$	380	$	368
Annual Electric Revenues
---	---	---	---	---
millions of Canadian dollars
	2021		2020
Residential	$	797	$	806
Commercial	****	407		405
Industrial	****	237		224
Other	****	27		31
Total	$	1,468	$	1,466
Q4 Electric Sales Volumes
---	---	---	---	---
GWh
	2021		2020
Residential	****	1,229		1,159
Commercial	****	730		712
Industrial	****	629		629
Other	****	38		36
Total	****	2,626		2,536
Annual Electric Sales Volumes
---	---	---	---	---
GWh
	2021		2020
Residential	****	4,661		4,652
Commercial	****	2,902		2,850
Industrial	****	2,480		2,341
Other	****	153		185
Total	****	10,196		10,028

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power increased $44 million to $263 million in Q4 2021, compared to $219 million in Q4 2020, and increased $96 million to $817 million in 2021, compared to $721 million in 2020. Increases in both periods were due to a provision for the Nova Scotia Cap-and-Trade program and higher commodity prices. See below for further information. Quarter-over-quarter, increases were partially offset by decreases due to changes in generation mix driven by emissions constraints. Year-over-year, changes in generation mix and higher Maritime Link assessment costs also contributed to the increase.

The provision for the Nova Scotia Cap-and-Trade program was $35 million in Q4 2021 and $38 million for the year ended December 31, 2021. This is due to higher than expected emissions primarily as a result of the delayed timing of Muskrat Falls Energy. The expense is accrued over the compliance period based on forecast emissions for the 2019 through 2022 period and is an estimate of expected costs but does not represent a fixed obligation.

Q4 Production Volumes
GWh
	2021		2020
Coal	****	1,224		1,249
Natural gas	****	371		351
Purchased power – other	****	196		235
Petcoke	****	208		148
Oil	****	14		26
Total non-renewables	****	2,013		2,009
Purchased power	****	536		509
Wind and hydro	****	243		215
Biomass	****	51		21
Total renewables	****	830		745
Total production volumes	****	2,843		2,754
Q4 Average Fuel Costs
	2021		2020
Dollars per MWh	$	93	$	80
Annual Production Volumes
---	---	---	---	---
GWh
	2021		2020
Coal	****	4,623		4,342
Natural gas	****	1,673		1,872
Purchased power – other	****	865		663
Petcoke	****	519		927
Oil	****	81		40
Total non-renewables	****	7,761		7,844
Purchased power	****	1,977		1,808
Wind and hydro	****	1,007		1,001
Biomass	****	160		106
Total renewables	****	3,144		2,915
Total production volumes	****	10,905		10,759
Annual Average Fuel Costs
	2021		2020
Dollars per MWh	$	75	$	67

Average fuel cost per MWh increased in Q4 2021, and for the year ended December 31, 2021 compared to the same periods in 2020. Quarter-over-quarter average fuel costs increased primarily due to the recognition of GHG emission expense as part of the Nova Scotia Cap-and-Trade Program and increased commodity pricing. See above for further information. Year-over-year, average fuel costs also increased due to changes in generation mix from lower carbon intensity sources such as IPPs, import and biomass generation and decreased generation from solid fuel and natural gas. Year-over-year, a higher Maritime Link assessment cost also contributed to the increase.

NSPI’s FAM regulatory balances increased $166 million, from a FAM regulatory liability of $21 million at December 31, 2020 to a FAM regulatory asset of $145 million at December 31, 2021, primarily due to under-recovery of current period fuel costs.

NSPI’s fuel costs are affected by commodity prices and generation mix, which is largely dependent on economic dispatch of the generating fleet, bringing 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.

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 and the Nova Scotia 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.

Regulatory Recovery Mechanisms

NSPI

NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (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.

NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers and provide a reasonable return to investors.

As part of the three-year fuel stability plan, electricity rates have been set to include the $145 million approved Maritime Link assessment for 2020 and amounts of $164 million and $162 million for 2021 and 2022, respectively. On December 16, 2020, the UARB approved NSPML’s application to recover from NSPI the costs associated with the Maritime Link in 2021 of approximately $172 million. This is subject to a holdback of $10 million, pending UARB agreement that benefits from the Maritime Link are realized for NSPI customers. NSPML has deferred collection and recognition of $23 million in depreciation expense in 2021. On August 9, 2021, NSPML filed a final cost application with the UARB to recover capital costs associated with the Maritime Link and approval of NSPML’s 2022 assessment. In December 2021, NSPML obtained an interim decision from the UARB approving interim rates beginning January 1, 2022, until receipt of the UARB’s decision on the application. On February 9, 2022, the UARB issued its decision relating to the Maritime Link Project, approving NSPML’s requested rate base of approximately $1.8 billion less costs that would not otherwise have been recoverable if incurred by NSPI. For further information on the UARB decision, refer to the “Business Overview and Outlook – Canadian Electric Utilities” section. Any difference between the amounts included in the fuel stability plan and those approved by the UARB through the NSPML interim assessment application will be addressed through the FAM.

Other Electric Utilities

All amounts are reported in USD, unless otherwise stated.

On March 24, 2020, Emera completed the sale of Emera Maine. For further detail, refer to the “Significant Items Affecting Earnings” section.

		Three months ended				Year ended
For the		December 31				December 31
millions of US dollars (except per share amounts)	****	2021		2020	****	2021		2020
Operating revenues – regulated electric	$	98	$	79	$	355	$	354
Regulated fuel for generation and purchased power (1)	$	52	$	35	$	175	$	145
Contribution to consolidated adjusted net income	$	4	$	5	$	16	$	24
Contribution to consolidated adjusted net income – CAD	$	5	$	8	$	20	$	33
Equity securities MTM gain	$	2	$	2	$	1	$	2
Contribution to consolidated net income	$	6	$	7	$	17	$	26
Contribution to consolidated net income – CAD	$	7	$	10	$	21	$	35
Contribution to consolidated adjusted earnings per common share – basic – CAD	$	0.02	$	0.03	$	0.08	$	0.13
Contribution to consolidated earnings per common share – basic – CAD	$	0.03	$	0.04	$	0.08	$	0.14
Net income weighted average foreign exchange rate – CAD/USD	$	1.27	$	1.28	$	1.26	$	1.34

(1) Regulated fuel for generation and purchased power includes transmission pool expense for year ended December 31, 2020 related to Emera Maine.

Other Electric Utilities’ contribution to consolidated adjusted net income is summarized in the following table:

	Three months ended		Year ended
For the	December 31		December 31
millions of US dollars	2021	2020	2021	2020
BLPC	$ 6	$ 5	$ 11	$ 20
GBPC	-	3	8	5
Emera Maine	-	-	-	4
Other	(2)	(3)	(3)	(5)
Contribution to consolidated adjusted net income	$ 4	$ 5	$ 16	$ 24

Excluding the change in MTM, Other Electric Utilities CAD contribution to consolidated net income decreased $3 million to $5 million in Q4 2021, compared to $8 million in Q4 2020 and decreased $13 million to $20 million in 2021, compared to $33 million in 2020. Year-over-year, the decrease was due to the recognition of a previously deferred corporate income tax recovery at BLPC in Q1 2020 related to the enactment of a lower corporate income tax rate in December 2018 and the sale of Emera Maine in Q1 2020. These decreases were partially offset by higher income at GBPC and lower interest expense.

The foreign exchange rate had minimal impact for the three months December 31, 2021. For the year ended December 31, 2021, the strengthening of the CAD decreased earnings and adjusted earnings by $1 million.

Operating Revenues – Regulated Electric

Operating revenues increased $19 million to $98 million in Q4 2021, compared to $79 million in Q4 2020 and increased $1 million to $355 million in 2021, compared to $354 million in 2020. The increases in both periods were due to higher fuel revenue at BLPC due to higher fuel prices. Year-over-year, the increase was partially offset by the sale of Emera Maine.

Electric sales volumes were higher in Q4 2021 with 330 GWh compared to 313 GWh in Q4 2020. For the year ended December 31, 2021, electric sales volumes were higher with 1,262 GWh compared to 1,240 GWh in 2020.

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power increased $17 million to $52 million in Q4 2021, compared to $35 million in Q4 2020 and increased $30 million to $175 million in 2021, compared to $145 million in 2020. The increases in both periods were due to higher fuel prices at BLPC. Year-over-year, the increase was partially offset by transmission pool expense at Emera Maine in 2020.

Regulatory Recovery Mechanisms

BLPC

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. BLPC’s fuel costs flow through a fuel pass-through mechanism which provides opportunity to recover all prudently incurred fuel costs from customers in a timely manner. The FTC approves the calculation of the fuel charge, which is adjusted on a monthly basis.

GBPC

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. GBPC’s fuel costs flow through a fuel pass-through mechanism which provides the opportunity to recover all prudently incurred fuel costs from customers in a timely manner.

GBPC maintains insurance for its generation facilities. As with most utilities, its transmission and distribution networks are not covered by commercial insurance. In 2019, Hurricane Dorian restoration costs for GBPC transmission and distribution network assets were $15 million. In January 2020, the GBPA approved the deferral of these costs through a regulated asset with recovery through rates over a five-year period. Recovery of the asset began January 1, 2021.

As a result of Hurricane Matthew in 2016, a regulatory asset was established to recover associated restoration costs. In 2017, as part of the recovery of costs incurred as a result of Hurricane Matthew, the GBPA approved a fixed per kWh fuel charge and allowed the difference between this and the actual cost of fuel to be applied to the Hurricane Matthew regulatory asset. In September 2021, GBPC filed an application for rate review with the GBPA. As part of its decision issued January 14, 2022 and effective April 1, 2022, the GBPA approved the continued amortization of the remaining regulatory asset over the three year period ending December 31, 2024.

Domlec

Domlec is regulated by the IRC. Rates are set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on rate base. Substantially all of Domlec fuel costs flow through a fuel pass-through mechanism which provides opportunity to recover prudently incurred fuel costs from customers in a timely manner.

Gas Utilities and Infrastructure

All amounts are reported in USD, unless otherwise stated.

		Three months ended				Year ended
For the		December 31				December 31
millions of US dollars (except per share amounts)	****	2021		2020	****	2021		2020
Operating revenues – regulated gas (1)	$	307	$	234	$	1,006	$	780
Operating revenues – non-regulated	****	2		3	****	12		12
Total operating revenue	$	309	$	237	$	1,018	$	792
Regulated cost of natural gas	$	139	$	80	$	375	$	221
Income from equity investments	$	4	$	4	$	16	$	14
Contribution to consolidated net income	$	44	$	35	$	157	$	122
Contribution to consolidated net income – CAD	$	55	$	45	$	198	$	162
Contribution to consolidated earnings per common share – basic – CAD	$	0.21	$	0.18	$	0.77	$	0.65
Net income weighted average foreign exchange rate – CAD/USD	$	1.26	$	1.30	$	1.26	$	1.33

(1) Operating revenues – regulated gas includes $12 million of finance income from Brunswick Pipeline (2020 - $11 million) for the three months ended December 31, 2021 and $46 million (2020 - $45 million) for the year ended December 31 2021; however, it is excluded from the gas revenues analysis below.

Gas Utilities and Infrastructure’s contribution to adjusted consolidated net income is summarized in the following table:

		Three months ended				Year ended
For the		December 31				December 31
millions of US dollars	****	2021		2020	****	2021		2020
PGS	$	17	$	13	$	77	$	52
NMGC	****	15		12	****	33		30
Other	****	12		10	****	47		40
Contribution to adjusted consolidated net income	$	44	$	35	$	157	$	122

Net Income

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

For the	Three months ended	Year ended
millions of US dollars	December 31	December 31
Contribution to consolidated net income – 2020	$ 35	$ 122
Increased gas operating revenues - see Operating Revenues - Regulated Gas below	73	226
Increased cost of natural gas sold - see Regulated Cost of Natural Gas below	(58)	(153)
Increased OM&G expenses year-over-year primarily due to higher labour and insurance costs at PGS and NMGC	2	(10)
Increased depreciation and amortization expense due to increased property, plant and equipment	(3)	(14)
Other	(5)	(14)
Contribution to consolidated net income – 2021	$ 44	$ 157

Gas Utilities and Infrastructure’s CAD contribution to consolidated net income increased $10 million in Q4 2021 to $55 million, compared to $45 million, in Q4 2020 and increased $36 million to $198 million compared to $162 million in 2020. The increases in both periods were due to higher base revenues at PGS as the result of a base rate increase effective January 1, 2021 and customer growth.

The impact of the change in the foreign exchange rate decreased CAD earnings for Q4 2021 and for the year ended December 31, 2021, by $1 million and $10 million respectively.

Operating Revenues – Regulated Gas

Gas Utilities and Infrastructure’s operating revenues increased $73 million to $307 million in Q4 2021, compared to $234 million in Q4 2020 and increased $226 million to $1,006 million in 2021, compared to $780 million in 2020. The increases in both periods were due to a base rate increase at PGS and NMGC effective January 1, 2021, customer growth at PGS, and higher purchased gas adjustment clause revenues at PGS and NMGC as a result of higher gas prices.

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

Q4 Gas Revenues
millions of US dollars
	****	2021		2020
Residential	$	167	$	122
Commercial	****	87		63
Industrial (1)	****	15		11
Other (2)	****	26		27
Total (3)	$	295	$	223

(1) Industrial includes sales to power generation customers.

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

(3) Excludes $12 million of finance income from Brunswick Pipeline (2020 – $11 million).

Annual Gas Revenues
millions of US dollars
	****	2021		2020
Residential	$	510	$	372
Commercial	****	301		207
Industrial (1)	****	53		41
Other (2)	****	96		115
Total (3)	$	960	$	735

(1) Industrial includes sales to power generation customers.

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

(3) Excludes $46 million of finance income from Brunswick Pipeline (2020 – $45 million).

Q4 Gas Volumes
Therms (millions)
	2021		2020
Residential	****	120		132
Commercial	****	212		220
Industrial	****	327		388
Other	****	27		59
Total	****	686		799
Annual Gas Volumes
---	---	---	---	---
Therms (millions)
	2021		2020
Residential	****	405		405
Commercial	****	799		767
Industrial	****	1,434		1,586
Other	****	137		298
Total	****	2,775		3,056

Regulated Cost of Natural Gas

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. Because the commodity portion of bundled sales is included in operating revenues, at the cost of the gas on a pass-through basis, there is no net earnings effect when a customer shifts to transportation-only sales.

Regulated cost of natural gas increased $59 million to $139 million in Q4 2021, compared to $80 million in Q4 2020 and increased $154 million to $375 million in 2021, compared to $221 million in 2020. The increases in both periods were due to higher gas prices at PGS and NMGC.

Gas sales by type are summarized in the following table:

Q4 Gas Volumes by Type
Therms (millions)
	2021	2020
System supply	177	197
Transportation	509	602
Total	686	799
Annual Gas Volumes by Type
---	---	---	---	---
Therms (millions)
	2021		2020
System supply	****	621		690
Transportation	****	2,154		2,366
Total	****	2,775		3,056

Regulatory Recovery Mechanisms

PGS

PGS is regulated by the FPSC. The FPSC sets rates at a level that allows utilities such as PGS to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital.

Other Cost Recovery

Fuel Recovery Clause

PGS recovers the costs it pays for gas supply and interstate transportation for system supply through its purchased gas adjustment (“PGA”) clause. This clause is designed to recover actual costs incurred by PGS for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, distribution, and sale of natural gas to its customers. These charges may be adjusted monthly subject to a cap approved annually by the FPSC.

Other Cost Recovery Clauses

The FPSC annually approves cost-recovery rates for conservation costs including a return on capital invested incurred in developing and implementing energy conservation programs. PGS has a Cast Iron/Bare Steel Pipe Replacement clause to recover the cost of accelerating the replacement of cast iron and bare steel distribution lines in the PGS system. In February 2017, the FPSC approved expansion of the Cast Iron/Bare Steel clause to allow recovery of accelerated replacement of certain obsolete plastic pipe. PGS estimates that the majority of cast iron and bare steel pipe will be removed from its system by the end of 2022, with replacement of obsolete plastic pipe continuing until 2028 under the rider.

NMGC

NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to collect total revenues equal to its cost of providing service, plus an appropriate return on invested capital.

Other Cost Recovery

Fuel Recovery Clause

NMGC recovers gas supply costs through a purchased gas adjustment clause (“PGAC”). This clause recovers NMGC’s actual costs for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, transportation, distribution, and sale of natural gas to its customers.

On a monthly basis, NMGC can adjust charges based on next month’s expected cost of gas and any prior month under-recovery or over-recovery. The NMPRC requires that NMGC annually file a reconciliation of the PGAC period costs and recoveries. NMGC must file a PGAC Continuation Filing with the NMPRC every four years to establish that continued use of the PGAC is reasonable and necessary. In December 2020, NMGC received approval of its PGAC Continuation Filing for the four-year period ending December 2024.

NMGC Winter Event Gas Cost Recovery

Weather Normalization Mechanism

In July 2019, the NMPRC approved changes to the company’s rate design to include a Weather Normalization Mechanism. This clause is designed to lower the variability of weather impacts during the October through April heating seasons. The Weather Normalization Mechanism allows customer rates and company revenue to be more predictable by partially removing the impact of warmer than usual or colder than usual weather. Weather-related revenue increases or decreases experienced from October to April are adjusted annually in October of the following heating season.

IMP Regulatory Asset

A portion of NMGC’s annual spend on infrastructure is for integrity management programs (“IMP”), or the replacement and update of legacy systems. These programs are driven both by NMGC integrity management plans and federal and state mandates. In December 2020, NMGC received approval through its rate case to defer costs through an IMP regulatory asset for certain of its IMP capital investments occurring between January 1, 2022 and December 31, 2023, and is seeking recovery of the regulatory asset in its rate case filed on December 13, 2021.

Other

		Three months ended				Year ended
For the	December 31				December 31
millions of Canadian dollars (except per share amounts)	****	2021		2020	****	2021		2020
Marketing and trading margin (1) (2)	$	39	$	22	$	102	$	38
Other non-regulated operating revenue	****	5		12	****	30		37
Total operating revenues – non-regulated	$	44	$	34	$	132	$	75
Income from equity investments	$	-	$	7	$	12	$	24
Contribution to consolidated adjusted net income (loss)	$	(44)	$	(23)	$	(198)	$	(252)
Gain on sale, net of tax and transaction costs (3)	****	-		-	****	-		309
Impairment charges, net of tax (4)	****	-		-	****	-		(26)
After-tax derivative MTM gain (loss) (5)	****	154		83	****	(214)		(12)
Contribution to consolidated net income (loss)	$	110	$	60	$	(412)	$	19
Contribution to consolidated adjusted earnings per common share – basic	$	(0.17)	$	(0.09)	$	(0.77)	$	(1.02)
Contribution to consolidated earnings per common share – basic	$	0.42	$	0.24	$	(1.60)	$	0.08

(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 pre-tax MTM gain of $212 million in Q4 2021 (2020-$109 million gain) and a loss of $289 million for the year ended December 31,2021 (2020 – $46 million loss).

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

(4) Net of income tax expense of $1 million for the year ended December 31, 2020.

(5) Net of income tax expense of $63 million for the three months ended December 31, 2021 (2020 – $33 million expense) and $86 million recovery for the year ended December 31, 2021 (2020 – $8 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				December 31
millions of Canadian dollars	2021		2020		2021		2020
Emera Energy	$	17	$	15	$	54	$	17
Corporate – see breakdown of adjusted contribution below	****	(57)		(32)	****	(231)		(255)
Emera Technologies	****	(4)		(5)	****	(17)		(12)
Other	****	-		(1)	****	(4)		(2)
Contribution to consolidated adjusted net income (loss)	$	(44)	$	(23)	$	(198)	$	(252)

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 foreign exchange forwards to manage the cash flow risk of forecasted USD cash inflows. Fluctuations in the foreign exchange 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 Canadian dollars		December 31
Contribution to consolidated net income (loss) – 2020	60	$	19
Increased marketing and trading margin - see Emera Energy below	17		64
Decreased interest expense in both periods due to the impact of a stronger CAD and lower interest rates. Year-over-year also decreased due to the repayment of corporate debt	6		35
Realized gain on hedges entered into to hedge foreign exchange earnings exposure	2		19
Revaluation of net deferred income tax assets and liabilities resulting from the enactment of a lower Nova Scotia provincial corporate income tax rate in Q1 2020, including 2 million recovery related to MTM	-		11
TGH award, net of tax and legal costs	(36)		(36)
Decreased income tax recovery primarily due to decreased losses before provision for income taxes.	(7)		(39)
Increased MTM gains, net of tax, quarter-over-quarter, primarily due to settlements and changes in existing positions at Emera Energy. These were partially offset by higher amortization on gas transportation assets in Q4 2021 and<br>the reversal of 2020 foreign exchange gains on cash flow hedges. Increased MTM losses, net of tax, year-over-year, primarily due to changes in existing positions and the reversal of 2020 foreign exchange gains on cash flow hedges.	71		(200)
2020 gain on sale and impairment charges, net of tax	-		(283)
Other	(3)		(2)
Contribution to consolidated net income (loss) – 2021	110	$	(412)

All values are in US Dollars.

Emera Energy

EES derives revenue and earnings from the wholesale marketing and trading of natural gas, electricity and other energy-related commodities and derivatives 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, US 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.

Marketingand Trading

Excluding the impact of MTM gains, marketing and trading margin increased $17 million in Q4 2021, compared to Q4 2020, due to higher spot and forward natural gas prices and increased volatility, which created profitable opportunity for Emera Energy’s transportation and storage portfolio.

For the year ended December 31, 2021, marketing and trading margin, excluding the impact of MTM losses, increased $64 million compared to 2020. This increase reflected the mid-February extreme weather event across the South-Central US which sharply increased pricing and volatility in adjacent markets where Emera Energy has a presence, and on which the business was able to capitalize. In addition, Q3 and Q4 presented opportunity, with a surge in global liquefied natural gas (“LNG”) pricing in particular enhancing gas market pricing and volatility in key geographies.

Corporate

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

		Three months ended				Year ended
For the		December 31				December 31
millions of Canadian dollars	****	2021		2020	****	2021		2020
Operating expenses (1)	$	1	$	17	$	28	$	54
Interest expense	****	65		71	****	264		299
Income tax recovery	****	(18)		(24)	****	(75)		(102)
Preferred dividends	****	14		11	****	50		45
TGH award	****	-		(36)	****	-		(36)
Income tax expense associated with the revaluation of Corporate deferred income tax assets and liabilities due to the 2020 reduction in the Nova Scotia provincial corporate income tax rate	****	-		-	****	-		9
Other (2)	****	(5)		(7)	****	(36)		(14)
Corporate adjusted net loss	$	(57)	$	(32)	$	(231)	$	(255)

(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 in Emera’s period end share price.

(2) Other includes realized foreign exchange gains on cash flow hedges to hedge foreign exchange earnings exposure, Q4 2021 includes a $5 million gain (2020 – $2 million gain) and year-ended December 31, 2021 gain of $18 million (2020 - $2 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 general economic downturns in markets served by Emera, 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.

The ongoing COVID-19 pandemic, including government measures to address the pandemic, have resulted in economic slowdowns in all markets served by Emera. The pace and strength of economic recovery varies among jurisdictions. On a consolidated basis, COVID-19 has not had a material financial impact to net earnings in 2021 and is not expected to have a material financial impact in 2022. For further information on the potential future impacts of COVID on Emera and its businesses, refer to the “Business Overview and Outlook” section.

There have been no significant customer defaults to date and as of December 31, 2021. Adjustments to the allowance for credit losses have increased but have not had a material impact on earnings. The full impact of potential credit losses due to customer non-payment is not known at this time but is not expected to be material. The utilities are continuing to monitor customer accounts and are working with customers on payment arrangements.

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 a $8.4 billion capital investment plan over the 2022-to-2024 period (including a $240 million equity investment in the LIL in 2022) and the potential for additional capital investments of $1 billion over the same period. 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. The extent of the future impact of COVID-19 on the profile of the Company’s capital investment plan cannot be predicted at this time. The Company has flexibility with respect to its capital investment plan and will continue to monitor current events and related impacts of COVID-19.

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 dividend reinvestment plan and ATM program.

Emera has credit facilities with varying maturities that cumulatively provide $3.8 billion of credit, with approximately $1.4 billion undrawn and available at December 31, 2021. The Company was holding a cash balance of $417 million at December 31, 2021. For further discussion, refer to the “Debt Management” section below. Refer to notes 23 and 25 in the consolidated financial statements for additional information regarding the credit facilities.

Consolidated Cash Flow Highlights

Significant changes in the Consolidated Statements of Cash Flows between the years ended December 31, 2021 and 2020 include:

millions of Canadian dollars	****	2021		2020		$ Change
Cash, cash equivalents and restricted cash, beginning of period	$	254	$	274	$	(20)
Provided by (used in):
Operating cash flow before changes in working capital	****	1,337		1,420		(83)
Change in working capital	****	(152)		217		(369)
Operating activities	$	1,185	$	1,637	$	(452)
Investing activities	****	(2,332)		(1,224)		(1,108)
Financing activities	****	1,311		(372)		1,683
Effect of exchange rate changes on cash, cash equivalents and restricted cash	****	(1)		(61)		60
Cash, cash equivalents, and restricted cash, end of period	$	417	$	254	$	163

Cash Flow from Operating Activities

Net cash provided by operating activities decreased $452 million to $1,185 million for the year ended December 31, 2021, compared to $1,637 million in 2020.

Cash from operations before changes in working capital decreased $83 million in 2021. The decrease was primarily due to the deferral of gas costs at NMGC resulting from the February 2021 extreme cold weather event, higher under-recovery of clause-related costs primarily due to higher natural gas prices at Tampa Electric and PGS, the TGH award in 2020, and the sale of Emera Maine in Q1 2020. This was partially offset by increased marketing and trading margin at Emera Energy and higher base revenue at PGS.

Changes in working capital decreased operating cash flows by $369 million due to unfavourable changes in cash collateral positions at Emera Energy, increased fuel inventory at Emera Energy and NSPI, unfavourable changes in accounts receivable at Tampa Electric and NMGC, the receipt of a 2019 income tax refund at NSPI in 2020, and timing of accounts payable payments at NMGC and PGS. This was partially offset by favourable changes in cash collateral positions on derivative instruments at NSPI.

Cash Flow used in Investing Activities

Net cash used in investing activities increased $1,108 million to $2,332 million for the year ended December 31, 2021, compared to $1,224 million in 2020. The increase was due to the proceeds of $1.4 billion received on the sale of Emera Maine in 2020, partially offset by lower capital expenditures in 2021.

Capital expenditures for the year ended December 31, 2021, including AFUDC, were $2,420 million compared to $2,668 million in 2020. Details of the 2021 capital spend by segment are shown below:

•	$1,408 million - Florida Electric Utility (2020 – $1,415 million);
•	$374 million - Canadian Electric Utilities (2020 – $342 million);
---	---
•	$111 million - Other Electric Utilities (2020 – $149 million);
---	---
•	$522 million - Gas Utilities and Infrastructure (2020 – $758 million); and
---	---
•	$5 million - Other (2020 – $4 million).
---	---

Cash Flow from Financing Activities

Net cash provided by financing activities increased $1,683 million to $1,311 million for the year ended December 31, 2021, compared to cash used in financing activities of $372 million in 2020. The increase was due to net proceeds from the issuance of long-term debt at Tampa Electric, NMGC, PGS and GBPC in 2021, repayment of long-term debt at TECO Finance in 2020, lower net repayments of committed credit facilities at TECO Finance and Emera, and the issuance of preferred shares. This was partially offset by higher net repayments of short-term debt at TEC and net proceeds from long-term debt in 2020 at NSPI.

Working Capital

As at December 31, 2021, Emera’s cash and cash equivalents were $394 million (2020 – $220 million) and Emera’s investment in non-cash working capital was $491 million (2020 – $266 million). Of the cash and cash equivalents held at December 31, 2021, $194 million was held by Emera’s foreign subsidiaries (2020 – $197 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, 2021, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:

millions of Canadian dollars	2022		2023		2024		2025		2026		Thereafter		Total
Long-term debt principal	$	462	$	590	$	827	$	504	$	3,479	$	8,914	$	14,776
Interest payment obligations (1)		611		592		580		561		481		6,589		9,414
Transportation (2)		563		437		372		323		297		2,627		4,619
Purchased power (3)		231		227		244		242		235		1,967		3,146
Fuel, gas supply and storage		694		104		45		40		25		–		908
Capital projects		359		93		3		1		1		–		457
Asset retirement obligations		8		7		2		2		1		395		415
Long-term service agreements (4)		49		66		47		32		26		83		303
Pension and post-retirement obligations (5)		32		38		33		33		33		168		337
Equity investment commitments (6)		240		–		–		–		–		–		240
Leases and other (7)		15		14		14		12		4		116		175
Demand side management		44		1		1		–		–		–		46
Long-term payable		5		5		–		–		–		–		10
	$	3,313	$	2,174	$	2,168	$	1,750	$	4,582	$	20,859	$	34,846

(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, 2021, 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 $142 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) Maintenance of certain generating equipment, services related to a generation facility and wind operating agreements, outsourced management of computer and communication infrastructure and vegetation management.

(5) 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.

(6) Emera has a commitment to make equity contributions to the LIL.

(7) Includes operating lease agreements for buildings, land, telecommunications services and rail cars, transmission rights and investment commitments.

NSPI has a contractual obligation to pay NSPML for the use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. As part of NSPI’s 2020 through 2022 fuel stability plan, rates have been set to include $164 million and $162 million for 2021 and 2022, respectively. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to UARB approval. Any difference between the amounts included in the NSPI fuel stability plan and those approved by the UARB through the NSPML interim assessment application will be addressed through the FAM. On August 9, 2021, NSPML filed a final capital cost application with the UARB seeking approval to recover capital costs associated with the Maritime Link and approval of NSPML’s 2022 assessment. In December 2021, NSPML obtained an interim decision from the UARB approving interim rates beginning January 1, 2022, until receipt of the UARB’s decision on the application. On February 9, 2022, the UARB issued its decision relating to the Maritime Link Project, approving NSPML’s requested rate base of approximately $1.8 billion less costs that would not otherwise have been recoverable if incurred by NSPI. For further information on the UARB decision, refer to the “Business Overview and Outlook – Canadian Electric Utilities” section.

Once Muskrat Falls and LIL have achieved full power, the commercial agreements between Emera and Nalcor require true ups to finalize the respective investment obligations of the parties relating to the Maritime Link and LIL.

Emera has committed to obtain certain transmission rights for Nalcor, if requested, to enable it to transmit energy which is not otherwise used in Newfoundland and Labrador or Nova Scotia. Nalcor has the right to transmit this energy from Nova Scotia to New England energy markets effective August 15, 2021, the date the NS Block commenced, and continuing for 50 years. As transmission rights are contracted, the obligations are included within “Leases and other” in the above table.

Forecasted Gross Consolidated Capital Expenditures

2022 forecasted gross consolidated capital expenditures are as follows:

millions of Canadian dollars		Florida<br> <br>Electric<br><br><br>Utility		Canadian<br> <br>Electric<br><br><br>Utilities		Other<br> <br>Electric<br><br><br>Utilities		Gas Utilities<br> <br>and<br><br><br>Infrastructure		Other		Total
Generation	$	352	$	170	$	47	$	–	$	–	$	569
New renewable generation		306		30		20		–		–		356
Transmission		80		150		2		–		–		232
Distribution		505		110		48		–		–		663
Gas transmission and distribution		–		–		–		562		–		562
Facilities, equipment, vehicles, and other		172		70		11		–		2		255
	$	1,415	$	530	$	128	$	562	$	2	$	2,637

Debt Management

In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to approximately $3.8 billion committed syndicated bank credit facilities in either CAD or USD per the table below.

millions of dollars		Credit<br><br><br>Facilities		Utilized		Undrawn<br><br><br>and<br> <br>Available
Emera – Unsecured committed revolving credit facility	June 2026	$	900	$	493	$	407
TEC (in ) – Unsecured committed revolving credit facility (1)	December 2026		800		246		554
NSPI – Unsecured committed revolving credit facility	December 2026		600		385		215
Emera – Unsecured non-revolving facility	December 2022		400		400		–
TEC (in ) – Unsecured non-revolving facility (2)	December 2022		500		500		–
TECO Finance (in ) – Unsecured committed revolving credit facility	December 2026		400		280		120
NMGC (in ) – Unsecured committed revolving credit facility	December 2026		125		22		103
NMGC (in ) – Unsecured non-revolving facility	September 2022		80		80		–
Other (in ) – Unsecured committed revolving credit facilities	Various		34		20		14

All values are in US Dollars.

(1) This facility is available for use by Tampa Electric and PGS. At December 31, 2021, $156 million USD was used by Tampa Electric and $90 million USD was used by PGS.

(2) This facility is available for use by Tampa Electric and PGS. At December 31, 2021, $400 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, 2021. Emera’s significant covenant is listed below:

	Financial Covenant	Requirement	As at<br><br><br>December 31, 2021
Emera
Syndicated credit facilities	Debt to capital ratio	Less than or equal to 0.70 to 1		0.57 : 1

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

Florida Electric Utility

On December 17, 2021, TEC entered into a $500 million USD unsecured, non-revolving credit facility with a maturity date of December 16, 2022. The credit facility contains customary representations and warranties, events of default, financial and other covenants and bears interest based on either the London Inter-Bank Offered Rate (“LIBOR”), prime rate, or the federal funds rate, plus a margin.

On December 17, 2021, TEC amended and restated its $800 million USD revolving credit facility. The amendment extended the maturity date from March 22, 2023 to December 17, 2026. There were no other significant changes in commercial terms from the prior agreement.

On May 25, 2021, TEC established a commercial paper program. Amounts available under the commercial paper program may be borrowed, repaid and reborrowed with the aggregate amount of the notes outstanding at any time not to exceed $800 million USD. The full amount of commercial paper issued is backed by TEC’s credit facility and results in an equal amount of its credit facility being considered drawn and unavailable.

On May 15, 2021, TEC repaid its $278 million USD, 5.4 per cent notes upon maturity. The notes were repaid using existing credit facilities.

On March 18, 2021, TEC completed an issuance of $800 million USD senior notes. The issuance included $400 million USD senior notes that bear interest at a rate of 2.40 per cent with a maturity date of March 15, 2031 and $400 million USD senior notes that bear interest at a rate of 3.45 per cent with a maturity date of March 15, 2051.

As a result of the $800 million USD senior notes issuance discussed above, on March 23, 2021, TEC repaid its $300 million USD non-revolving term loan. TEC also repaid its $150 million USD accounts receivable collateralized borrowing facility and the agreement subsequently matured and terminated on March 22, 2021.

Canadian Electric Utilities

On December 3, 2021, NSPI amended its operating credit facility to extend the maturity from October 2024 to December 2026. There were no other significant changes in commercial terms from the prior agreement.

Other Electric

On December 16, 2021, GBPC entered into a $75 million USD 4.00 per cent term loan with a maturity date of December 31, 2026. Proceeds from this loan were used to repay existing, non-revolving term loans totaling $55 million USD and to fund operations.

Gas Utilities and Infrastructure

On December 17, 2021, NMGC amended and restated its $125 million USD revolving credit facility. The amendment extended the maturity date from March 22, 2023 to December 17, 2026. There were no other significant changes in commercial terms from the prior agreement.

On July 16, 2021, Brunswick Pipeline extended the maturity date of its $250 million credit facility from May 17, 2023 to June 30, 2025. There were no other significant changes in commercial terms from the prior agreement.

On March 25, 2021, NMGC entered into a $100 million USD unsecured, non-revolving credit facility with a maturity date of September 23, 2022. The credit facility contains customary representations and warranties, events of default, financial and other covenants and bears interest based on either the LIBOR, prime rate, or the federal funds rate, plus a margin. Proceeds from this issuance were used to pay for higher than normal gas costs as a result of the severe cold weather event in February 2021 (for more detail, refer to “Business Overview and Outlook – Gas Utilities and Infrastructure” section).

On February 5, 2021, NMGC completed an issuance of $220 million USD senior notes. The issuance included $70 million USD senior notes that bear interest at a rate of 2.26 per cent with a maturity date of February 5, 2031, $65 million USD senior notes that bear interest at a rate of 2.51 per cent and with a maturity date of February 5, 2036, and $85 million USD senior notes that bear interest at a rate of 3.34 per cent with a maturity date of February 5, 2051. Proceeds from this issuance were used to repay a $200 million USD note due in 2021, which was classified as long-term debt at December 31, 2020.

Other

On December 17, 2021, TECO Finance amended and restated its $400 million USD revolving credit facility. The amendment extended the maturity date from March 22, 2023 to December 17, 2026. There were no other significant changes in commercial terms from the prior agreement.

On December 3, 2021, Emera extended the maturity date of its $400 million non-revolving term loan from December 16, 2021 to December 16, 2022. There were no other significant changes in commercial terms from the prior agreement.

On July 23, 2021, Emera extended the maturity date of its $900 million unsecured committed revolving credit facility from June 30, 2024 to June 30, 2026. There were no other significant changes in commercial terms from the prior agreement.

From the $750 million USD senior notes issuance discussed above, on June 15, 2021, Emera US Finance LP repaid its previously outstanding $750 million USD senior notes on maturity.

Preferred Share Issuances

Credit Ratings

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

	Fitch	S&P	Moody’s	DBRS
Emera Inc.	BBB (Stable)	BBB- (Stable)	Baa3 (Stable)	N/A
TECO Energy/TECO Finance	N/A	BBB- (Stable)	Baa1 (Positive)	N/A
TEC	A(Stable)	BBB+ (Stable)	A3 (Positive)	N/A
NMGC	BBB+ (Stable)	N/A	N/A	N/A
NSPI	N/A	BBB+ (Stable)	N/A	A (low) (Stable)

Guaranteed Debt

On June 4, 2021, Emera US Finance LP completed an issuance of $750 million USD senior notes. From the proceeds of the issuance, on June 15, 2021, Emera US Finance LP repaid its previously outstanding $750 million USD senior notes on maturity. As of December 31, 2021, 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.

On January 1, 2021 the Company adopted ASU 2020-09, Debt (Topic 470):Amendments to SEC Paragraphs pursuant to SEC Release No 33-10762. In the release, the SEC adopted final rules that amend the financial disclosure requirements for subsidiary issuers and guarantors of registered debt securities under Rule 3-10 of Regulation S-X, permitting registrants to disclose summarized financial information for each subsidiary issuer and guarantor. These rules were codified in Rule 13-01 of Regulation S-X. In compliance thereof, 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 include 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 Canadian dollars	2021
Loss from operations	$ (21)
Net losses (1)	$ (86)

(1) Includes $222 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 Canadian dollars	2021
Current assets (1)	$ 329
Goodwill	5,628
Other assets (2)	6,027
Total assets (3)	$ 11,984
Current liabilities (4)	$ 888
Long-term liabilities (5)	6,403
Total liabilities	$ 7,291

(1) Includes $140 million in amounts due from non-guarantor subsidiaries.

(2) Includes $5,749 million in amounts due from non-guarantor subsidiaries.

(3) Excludes investments in non-guarantor subsidiaries. Consolidated Emera total assets are $34,244 million.

(4) Includes $346 million due to non-guarantor subsidiaries.

(5) Includes $776 million due to non-guarantor subsidiaries.

Share Capital

Emera

As at December 31, 2021, Emera had 261.07 million (2020 – 251.43 million) common shares issued and outstanding. For the year ended December 31, 2021, 9.64 million common shares were issued (2020 – 8.95 million) for net proceeds of $537 million (2020 – $489 million).

As at December 31, 2021, Emera had 58 million preferred shares issued and outstanding (2020 – 41 million).

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 2022 for defined benefit pension plans is expected to be $41 million (2021 – $41 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 within an acceptable level of risk for the pension fund investments.

To 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 $46 million for 2022 (2021 – $45 million).

Defined Benefit Pension Plan Summary

in millions of Canadian dollars
Plans by region	TECO Energy			****	NSPI	****	Caribbean	****	Total
Assets as at December 31, 2021		$	1,171	$	1,521	$	10	$	2,702
Accounting obligation at December 31, 2021		$	1,078	$	1,531	$	15	$	2,624
Accounting expense during fiscal 2021		$	13	$	9	$	1	$	23

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, 2021 totalled $200 million (2020 – $582 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, 2021:

TECO Energy has issued a guarantee in connection with SeaCoast’s performance of obligations under a gas transportation precedent agreement. The guarantee is for a maximum potential amount of $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 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.

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.

NSPI has issued guarantees in the amount of $15 million USD on behalf of its subsidiary, NS Power Energy Marketing Incorporated (“NSPEMI”), to secure obligations under purchase agreements with third- party suppliers and $85 million USD related to a 15-year natural gas transportation commitment. NSPI has $118 million USD (2020 - $18 million USD) of guarantees outstanding with terms of varying lengths and will be renewed as required.

The Company has standby letters of credit and surety bonds in the amount of $148 million USD (December 31, 2020 - $55 million USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed annually as required.

Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The expiry date of this letter of credit was extended to June 2022. The amount committed as at December 31, 2021 was $64 million (December 31, 2020 - $63 million).

DIVIDEND PAYOUT RATIO

Emera has provided annual dividend growth guidance of four to five per cent through 2024.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 Incorporated’s common share dividends paid in 2021 were $2.5750 ($0.6375 in Q1, Q2, and Q3 and $0.6625 in Q4) per common share and $2.4750 ($0.6125 in Q1, Q2, and Q3 and $0.6375 in Q4) per common share for 2020, representing a dividend payout ratio of 129 per cent in 2021 (2020 – 65 per cent) and a dividend payout ratio of adjusted net income of 91 per cent in 2021 (2020 - 91 per cent).

On September 24, 2021, the Emera Board of Directors approved an increase in the annual common share dividend rate to $2.65 from $2.55. The first quarterly dividend payment at the increased rate was paid on November 15, 2021.

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<br>Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $149 million for the year ended December 31, 2021 (2020 - $139 million). NSPML is accounted for as an equity investment and therefore,<br>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<br>Obligations” sections.

•

Natural gas transportation capacity purchases from M&NP are reported in the Consolidated Statements of Income.<br>Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $19 million for the year ended December 31, 2021 (2020 - $18 million).

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There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Consolidated Balance Sheets as at December 31, 2021 and at December 31, 2020.

ENTERPRISE RISK AND RISK MANAGEMENT

Emera has a business-wide risk management process, overseen by its Enterprise Risk Management Committee 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 Enterprise Risk Management Committee to ensure such risks are appropriately assessed, monitored and subject to appropriate controls and, in the case of certain credit risks, controlled within predetermined financial risk tolerances established through approved policies.

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 change in regulatory frameworks, shifts in government policy, 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. Costs and investments can be recovered upon approval by the respective regulator as an adjustment to rates and/or riders, which normally requires a public hearing process or may be mandated by other governmental bodies. Emera also holds investments in entities in which it has significant influence, and which are subject to regulatory and political risk including NSPML, LIL, M&NP and Lucelec.

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 Canada (“REC”). The agreement provides for a predetermined toll increase in the fifth and fifteenth year of the contract.

Changes in government and shifts in government policy 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 US 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 could adversely impact PGS and NMGC.

Emera’s rate-regulated subsidiaries are subject to regulatory processes. 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. The subsidiaries manage this regulatory 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.

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 the 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 is on track to achieve reductions of carbon dioxide emissions of approximately 60 per cent from 2005 levels. NSPI expects to exceed the new 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 as well as the goal to phase out coal-fired electricity generation by 2030. Failure to meet such goals by 2030 could result in material fines, penalties, other sanctions and adverse reputational impacts. NSPI continues to work with both the provincial and federal governments on measures to seek to address their carbon reduction goals. Within Emera’s natural gas utilities, there are ongoing efforts to reduce methane and carbon dioxide emissions through replacement of aging infrastructure, more efficient operations, operational and supply chain optimization, 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 contributes 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 to 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 is also 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 committed to compliance with all 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.

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, electrical utilities operating in Atlantic Canada could see lower demand in winter months if temperatures are warmer 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.

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.

In 2019, NSPI completed registration under the Nova Scotia Cap-and-Trade Program Regulations. This provincial carbon pricing program meets the benchmark set by the Government of Canada. In the United States, air emissions, including GHG emissions, are regulated pursuant to the Clean Air Act. Individual states continue to develop or administer GHG reduction initiatives. 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 information technology systems and network 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.

Cyberattacks can reach the Company’s networks with access to critical assets and information via their interfaces with less critical internal networks or via the public internet. Cyberattacks can also occur via personnel with direct access to critical assets or trusted networks. An outbreak of infectious disease, a pandemic or a similar public health threat, such as COVID-19, may cause disruption in normal working patterns including wide scale “work from home” policies, which could increase cybersecurity risk as the quantity of both cyberattacks and network interfaces increases. Refer to the “Public Health Risk” section below. 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 or the unavailability, 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.

Should such cyberattacks or unauthorized accesses materialize, 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 and could materially adversely affect Emera’s business and financial results including its reputation and standing 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 that 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, periodic security testing, program maturity objectives, strategy derived, in part, on the National Institute of Standards and Technology’s Cyber Security Framework, 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 information technology including, but not limited to, those mandated by bodies such as the North American Electric Reliability Corporation and Northeast Power Coordinating Council. The status of key elements of the Company’s cybersecurity program is reported to the Risk and Sustainability Committee.

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 ConsumptionRisk

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, customers’ focus on energy efficiency, 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 Canadian dollar and, particularly, the US dollar, which could positively or adversely affect results.

Consistent with the Company’s risk management policies, Emera manages currency risks through matching US denominated debt to finance its US operations and may use foreign currency derivative instruments to hedge specific transactions and earnings exposure. The Company may enter foreign exchange forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases, revenue streams and capital 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 foreign exchange.

The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries do not impact net income as they are reported in 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 property, plant and equipment and the risk associated with changes in interest rates could have an adverse effect on the cost of financing. The Company’s future access to capital and cost 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 and regulatory framework, the ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to climate change-related impacts, including increased frequency and severity of hurricanes and other severe weather events. A decrease in a credit rating could result in higher interest rates in future financings, increase borrowing costs under certain existing credit facilities, limit access to the commercial paper market or limit the availability of adequate credit support for subsidiary operations. For certain derivative instruments, if the credit ratings of the Company were reduced below investment grade, the full value of the net liability of these positions could be required to be posted as collateral. Emera manages these risks by actively monitoring and managing key financial metrics with the objective of sustaining investment grade credit ratings.

The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to reduce the earnings volatility derived from stock-based compensation.

Interest RateRisk

Emera utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturities. The Company will, from time to time, issue long-term debt or enter interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt.

For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt costs are recovered from customers. Regulatory ROE will generally follow the direction of interest rates, such that regulatory ROE’s are likely to fall in times of reducing interest rates and rise in times of increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory process. Rising interest rates may also negatively affect the economic viability of project development and acquisition initiatives.

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. Counterparty creditworthiness and the ability of key partners, suppliers and customers to perform their contractual obligations may be affected by economic impacts related to COVID-19.

Emera manages this counterparty risk through due diligence and 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. Emera may also seek recovery of unpaid amounts or damages through applicable bankruptcy, insolvency or similar proceedings.

Country Risk

Earnings outside of Canada constituted 78 per cent of Emera’s earnings in 2021 (2020 – 73 per cent) with the majority from the US. Emera’s investments are currently in regions where political and economic risks are considered by the Company to be acceptable. 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. The Company’s commercial arrangements, including the combination of supply and purchase agreements, asset management agreements, pipeline transportation agreements and financial hedging instruments are all used to manage and mitigate this risk. In addition, its credit policies, counterparty credit assessments, market and credit position reporting, and other risk management and reporting practices, are also used to manage and mitigate this risk.

Regulated Utilities

A large portion of the Company’s utility fuel supply comes from international suppliers and therefore may be exposed to broader global conditions, which may include impacts on delivery reliability and price, despite contracted terms. The Company seeks to manage this risk using financial hedging instruments and physical contracts and through contractual protection with counterparties, where applicable.

The majority of Emera’s regulated electric and gas utilities have adopted and implemented fuel adjustment mechanisms and purchased gas adjustment mechanisms respectively, which has further helped manage commodity price risk, as the regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred fuel and gas costs.

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.

To 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.

FutureEmployee 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, 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. Two of the largest drivers of cost are investment performance and interest rates, which are affected by global financial and capital markets. Depending on future interest rates and actual versus expected investment performance, Emera could be required to make larger contributions in the future to fund these plans, which could 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 every three to 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 33 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.

Information Technology Risk

Emera relies on various information technology 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 information technology, 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 information technology solutions, resulting in increased project risks associated with the implementation of these solutions.

Emera manages these information technology 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, ensure that continuity is maintained in the event of any 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, activities of third parties, damage to facilities, solar panels and infrastructure caused by hurricanes, storms, falling trees, lightning strikes, floods, fires and other natural disasters, and disruption of fuel supply chain caused by damage to, or cyber-attacks on, third party storage and pipeline facilities. Natural gas pipeline operations can also be impacted by risks such as leaks, explosions, mechanical failures, activities of third parties and damage to the pipelines 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.

Emera manages these risks by investing in a highly skilled workforce, operating prudently, preventative maintenance, 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.

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 that 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 Enterprise Risk Management Committee, whose responsibilities include preparing an updated risk dashboard and heat map presented at regular meetings of the Board’s Risk and Sustainability Committee. Furthermore, a corporate team independent from operations is responsible for tracking and reporting on market and credit risks.

The Company manages exposure to normal operating and market risks relating to commodity prices, foreign exchange, interest rates and share prices through contractual protections with counterparties where practicable, and by using financial instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. 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. 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, any changes in fair value are 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, and for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. These derivatives are recorded at fair value on the balance sheet as derivative assets or liabilities. 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 in regulated fuel for generation and purchased power, inventory or property, plant and equipment, depending on the nature of the item being economically hedged. Management believes any gains or losses resulting from settlement of these derivatives will be refunded to or collected from customers in future rates. Tampa Electric and PGS have no derivatives related to hedging as a result of a FPSC approved five-year moratorium on hedging of natural gas purchases which ends on December 31, 2022. Tampa Electric’s moratorium on hedging of natural gas purchases will continue through December 31, 2024, as a result of Tampa Electric’s 2021 rate case settlement agreement.

Derivatives that do not meet any of the above criteria are designated as HFT and are recognized on the balance sheet at fair value. All gains or losses are recognized in net income of the period unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category when another accounting treatment applies.

Hedging Items Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to derivatives in valid hedging relationships:

As at	December 31			December 31
millions of Canadian dollars	2021			2020
Derivative instrument assets (current and other assets)		$	-		$	1
Net derivative instrument assets		$	-		$	1

Hedging Impact Recognized in Net Income

The Company recognized gains (losses) related to the effective portion of hedging relationships under the following categories:

For the	Year ended December 31
millions of Canadian dollars	2021		2020
Operating revenues – regulated	$	-		$	(2)
Non-regulated fuel for generation and purchased power	****	1			-
Effective net gains (losses)	$	1		$	(2)

The effective net losses reflected in the above table are offset in net income by the hedged item realized in the period.

Regulatory Items Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to derivatives receiving regulatory deferral:

As at	December 31			December 31
millions of Canadian dollars	2021			2020
Derivative instrument assets (current and other assets)		$	237		$	14
Regulatory assets (current and other assets)		****	23			65
Derivative instrument liabilities (current and long-term liabilities)		****	(20)			(62)
Regulatory liabilities (current and long-term liabilities)		****	(241)			(15)
Net asset (liability)		$	(1)		$	2

Regulatory Impact Recognized in Net Income

The Company recognized the following net gains (losses) related to derivatives receiving regulatory deferral as follows:

For the	Year ended December 31
millions of Canadian dollars	2021		2020
Regulated fuel for generation and purchased power (1)	$	34		$	(21)
Net gains (losses)	$	34		$	(21)

(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 in “Regulated fuel for generation and purchased power” when the hedged item is consumed.

HFT Items Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to HFT derivatives:

As at	December 31			December 31
millions of Canadian dollars	2021			2020
Derivative instrument assets (current and other assets)		$	53		$	68
Derivative instrument liabilities (current and long-term liabilities)		****	(662)			(275)
Net derivative instrument liability		$	(609)		$	(207)

HFT Items Recognized in Net Income

The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives in net income:

For the	Year ended December 31
millions of Canadian dollars	2021		2020
Non-regulated operating revenues	$	(138)		$	204
Non-regulated fuel for generation and purchased power	****	-			(4)
Net gains (losses)	$	(138)		$	200

Other Derivatives Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to other derivatives:

As at	December 31			December 31
millions of Canadian dollars	2021			2020
Derivative instrument assets (current and other assets)		$	11		$	15
Derivative instrument liabilities (current and long-term liabilities)		****	-			(1)
Net derivative instrument assets		$	11		$	14

Other Derivatives Recognized in Net Income

The Company recognized in net income the following realized and unrealized gains (losses) related to other derivatives:

For the	Year ended December 31
millions of Canadian dollars	2021		2020
OM&G	$	26		$	(4)
Other income, net	****	3			13
Net gains	$	29		$	9

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, 2021 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, 2021, 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 the use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill, and long-lived assets impairment assessments, income taxes, asset retirement obligations, and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise.

Management has analyzed the impact of the COVID-19 pandemic on its estimates and assumptions and concluded that no material adjustments were required for the year ended December 31, 2021.

The extent of the future impact of COVID-19 on the Company’s financial results and business operations cannot be predicted at this time and will depend on future developments, including the duration and severity of the pandemic, timing and effectiveness of vaccinations, further potential government actions and future economic activity and energy usage. Actual results may differ significantly from these estimates.

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 accounting policies for non-rate-regulated companies. These accounting policy differences occur when the 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.

The Company has recorded $2,566 million (2020 - $1,584 million) of regulatory assets and $2,055 million (2020 - $1,961 million) of regulatory liabilities as at December 31, 2021.

Accumulated Reserve – Cost of Removal

Tampa Electric, PGS, NMGC and NSPI recognize non-asset retirement obligation (“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 property, plant and equipment 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. The balance of the Accumulated reserve – COR within regulatory liabilities was $819 million at December 31, 2021 (2020 - $865 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 9.2 years (9.0 years for 2021 benefit cost) for the Canadian plans and a weighted average of 11.1 years for the US 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:

				2020
		Expected<br> <br>return on<br><br><br>plan assets		Discount rate for<br><br><br>benefit cost purposes		Expected<br> <br>return on<br><br><br>plan assets
TECO Energy Group Retirement Plan	2.38%	****	6.70%		3.22%		7.00
TECO Energy Group Supplemental Executive Retirement Plan (1)	1.84%	****	N/A		2.78%		N/A
TECO Energy Group Benefit Restoration Plan (1)	1.71%	****	N/A		2.81%		N/A
TECO Energy Post-retirement Health and Welfare Plan	2.47%	****	N/A		3.32%		N/A
New Mexico Gas Company Retiree Medical Plan	2.49%	****	4.00%		3.32%		3.25%
NSPI	2.59%, 2.85%	****	5.25%		3.13%, 3.21%		5.75%
C Salaried	4.25%	****	6.00%		4.25%		6.00%
C Union	5.65%	****	5.65%		5.00%		5.00%

All values are in British Pounds.

(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 $85 million in 2021 (2020 - $87 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 2021 benefit cost of $1 million and $3 million respectively (2020 - $6 million and $5 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 the estimates included in the determination of unbilled revenue, actual results may differ from the estimate. At December 31, 2021, unbilled revenues totalled $318 million (2020 – $286 million) on total regulated operating revenues of $5,926 million (2020 – $5,476 million).

Property, Plant and Equipment

Property, plant and equipment represents 59 per cent of total assets on the Company’s balance sheet. Included in “Property, plant and equipment” are 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 property, plant and equipment are determined based on depreciation studies and require appropriate regulatory approval. Due to the magnitude of the Company’s property, plant and equipment, changes in estimated depreciation rates can have a material impact on depreciation expense and accumulated depreciation.

Depreciation expense was $877 million for the year ended December 31, 2021 (2020 – $860 million).

Goodwill Impairment Assessments

Goodwill is subject to an annual assessment for impairment at the reporting unit level with interim impairment tests performed when impairment indicators are present. Reporting units are generally determined at the operating segment level or one level below the operating segment level. Reporting units with similar characteristics are grouped for the purpose of determining impairment, if any, of goodwill. 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. Significant assumptions used in the qualitative assessment include macroeconomic conditions, industry and market considerations, and overall financial performance, among other factors.

If the Company performs the qualitative assessment and determines that it is more likely than not that its fair value is less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a quantitative test is performed. The quantitative test compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense. Significant assumptions used in estimating the fair value include discount and growth rates, rate case assumptions, valuation of the reporting units’ net operating loss (“NOL”), utility sector market performance and transactions, projected operating and capital cash flows, and the fair value of debt. Adverse changes in assumptions could result in a future material impairment of the goodwill assigned to Emera’s reporting units with goodwill. As part of the goodwill impairment assessment, management considered potential impacts of the COVID-19 pandemic on future earnings of the reporting units.

As of December 31, 2021, the Company had goodwill with a total carrying amount of $5,696 million (December 31, 2020 – $5,720 million). This goodwill represents the excess of the acquisition purchase price for TECO Energy (Tampa Electric, PGS and NMGC reporting units) and GBPC over the fair values assigned to identifiable assets acquired and liabilities assumed. The change in the carrying value of goodwill from 2020 to 2021 was a result of changes to the Canadian dollar on the goodwill balances.

As of December 31, 2021, $5.6 billion of Emera’s goodwill was related to TECO Energy (Tampa Electric, PGS and NMGC reporting units). Qualitative assessments were performed for these reporting units given the significant excess of fair value over carrying amounts calculated during the last quantitative test in Q4 2019. Management concluded that it was more likely than not that the fair value of these reporting units exceeded their respective carrying amounts, including goodwill. As such, no quantitative testing was required.

As of December 31, 2021, $68 million of Emera’s goodwill was related to GBPC. In Q4 2021, the Company performed a quantitative impairment assessment for GBPC as this reporting unit is more sensitive to changes in assumptions due to limited excess of fair value over the carrying value. The assessment estimated that the fair value of the reporting unit exceeded its carrying value, including goodwill, by approximately 12 per cent. For further detail, refer to note 22 to the consolidated financial statements.

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.

Management considered whether the potential impacts of the COVID-19 pandemic on undiscounted future cash flows could indicate that long-lived assets are not recoverable. As at December 31, 2021, there were no indications of impairment of Emera’s long-lived assets.

No impairment charges were recognized during the year ended December 31, 2021. In 2020, impairment charges of $25 million ($26 million after tax) were recognized on certain assets and recorded in “Impairment charge” on the Consolidated Income Statement.

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 recovered from future taxable income 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 occurring 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 (“ARO”)

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 “Property, plant and equipment” 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 generation, transmission and distribution assets may have conditional AROs, which are required to be estimated and recorded as a liability. 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, 2021, AROs recorded on the balance sheet were $174 million (2020 – $178 million). The Company estimates the undiscounted amount of cash flow required to settle the obligations is approximately $422 million (2020 - $432 million), which will be incurred between 2022 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 policies that are applicable to, and adopted by the Company in 2021, are described as follows:

Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity

The Company adopted Accounting Standard Update (“ASU”) 2020-06, Debt - Debt with Conversion and Other Options(Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity ’ s Own Equity (Subtopic 815-40) effective January 1, 2021 using the modified retrospective approach. The standard simplifies the accounting for convertible debenture debt instruments and convertible preferred stock, in addition to amending disclosure requirements. The standard also updates guidance for the derivative scope exception for contracts in an entity’s own equity and the related earnings per share guidance. There was no material impact on the consolidated financial statements as a result of the adoption of this standard.

Guaranteed Debt Securities Disclosure Requirements

The Company adopted ASU 2020-09, Debt (Topic 470): Amendments to SEC Paragraphs pursuant to SEC Release No. 33-10762 effective December 31, 2021. The standard aligns with new SEC rules relating to changes to the disclosure requirements for certain registered debt securities that are guaranteed. The changes include simplifying and focusing the disclosure models, enhancing certain narrative disclosures and permitting the disclosures to be made outside of the financial statements. As a result of adopting this standard, the disclosures related to certain registered debt securities that are guaranteed were amended and removed from the consolidated financial statements and added to Management’s Discussion & Analysis.

Future Accounting Pronouncements

The Company considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board (“FASB”). The ASUs that have been issued by FASB, but are not yet effective, were assessed and determined to be either not applicable to the Company or have an insignificant impact on the consolidated financial statements.

SUMMARY OF QUARTERLY RESULTS

For the quarter ended<br><br><br>millions of Canadian dollars	****	Q4		Q3			Q2			Q1		Q4		Q3		Q2		Q1
(except per share amounts)	****	2021		2021			2021			2021		2020		2020		2020		2020
Operating revenues	$	1,868	$	1,148		$	1,137		$	1,612	$	1,537	$	1,163	$	1,169	$	1,637
Net income attributable to common shareholders	$	324	$	(70	)	$	(17	)	$	273	$	273	$	84	$	58	$	523
Adjusted net income attributable to common shareholders	$	168	$	175		$	137		$	243	$	188	$	166	$	118	$	193
Earnings per common share – basic	$	1.24	$	(0.27	)	$	(0.07	)	$	1.08	$	1.09	$	0.34	$	0.24	$	2.14
Earnings per common share – diluted	$	1.20	$	(0.27	)	$	(0.07	)	$	1.08	$	1.08	$	0.34	$	0.23	$	2.13
Adjusted earnings per common share – basic	$	0.64	$	0.68		$	0.54		$	0.96	$	0.75	$	0.67	$	0.48	$	0.79

Quarterly operating revenues and adjusted net income attributable to common shareholders 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.

EX-99.3

EMERA INCORPORATED

Consolidated

Financial Statements

December 31, 2021 and 2020

MANAGEMENT REPORT

Management's Responsibility for Financial Reporting

The accompanying consolidated financial statements of Emera

Incorporated and the information in this

annual report are the responsibility of management and have

been approved by the Board of Directors

(“Board”).

The consolidated financial statements have been prepared

by management in accordance with United

States Generally Accepted Accounting Principles. When alternative

accounting methods exist,

management has chosen those it considers most appropriate

in the circumstances. In preparation of

these consolidated financial statements, estimates are sometimes

necessary when transactions affecting

the current accounting period cannot be finalized with

certainty until future periods. Management

represents that such estimates, which have been properly reflected

in the accompanying consolidated

financial statements, are based on careful judgments and

are within reasonable limits of materiality.

Management has determined such amounts on a reasonable

basis in order to ensure that the

consolidated financial statements are presented fairly in

all material respects. Management has prepared

the financial information presented elsewhere in the annual report

and has ensured that it is consistent

with that in the consolidated financial statements.

Emera Incorporated maintains effective systems

of internal accounting and administrative controls,

consistent with reasonable cost. Such systems are designed to

provide reasonable assurance that the

financial information is reliable and accurate, and that

Emera Incorporated's assets are appropriately

accounted for and adequately safeguarded.

The Board is responsible for ensuring that management

fulfils its responsibilities for financial reporting

and is ultimately responsible for reviewing and approving

the consolidated financial statements. The

Board carries out this responsibility principally through its

Audit Committee.

The Audit Committee is appointed by the Board, and its

members are directors who are not officers or

employees of Emera Incorporated. The Audit Committee meets

periodically with management, as well as

with the internal auditors and with the external auditors, to discuss

internal controls over the financial

reporting process, auditing matters and financial reporting

issues, to satisfy itself that each party is

properly discharging its responsibilities, and to review the annual

report, the consolidated financial

statements and the external auditors' report. The Audit

Committee reports its findings to the Board for

consideration when approving the consolidated financial statements

for issuance to the shareholders.

The Audit Committee also considers, for review by the Board

and approval by the shareholders, the

appointment of the external auditors.

The consolidated financial statements have been audited

by Ernst & Young

LLP,

the external auditors, in

accordance with Canadian Generally Accepted Auditing Standards

and with the standards of the Public

Company Accounting Oversight Board. Ernst & Young

LLP has full and free access to the Audit

Committee.

February 14, 2022

“Scott Balfour”

“Gregory Blunden”

President and Chief Executive Officer

Chief Financial Officer

Report of Independent Registered Public Accounting Firm

the Shareholders and the Board of Directors of Emera

Incorporated

Opinion on the Consolidated Financial Statements

We have audited the accompanying Consolidated

Balance Sheets of Emera Incorporated (the

“Company“) as of December 31, 2021 and 2020, the related Consolidated

Statements of Income,

Consolidated Statements of Comprehensive Income,

Consolidated Statements of Changes in Equity and

Consolidated Statements of Cash Flows for the years

then ended, and the related notes (collectively

referred to as the “consolidated financial statements“).

In our opinion, the consolidated financial

statements present fairly,

in all material respects, the consolidated financial position

of the Company as of

December 31, 2021 and 2020, and the consolidated results

of its operations and its consolidated cash

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

31, 2021, in conformity with United States

generally accepted accounting principles.

Basis for Opinion

These consolidated financial statements are the responsibility

of the Company‘s management. Our

responsibility is to express an opinion on the Company‘s

consolidated financial statements based on our

audits. We are a public accounting firm registered

with the Public Company Accounting Oversight Board

(United States) (“PCAOB”) and are required to be independent

with respect to the Company in

accordance with the U.S. federal securities laws and the

applicable rules and regulations of the Securities

and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the

standards of the PCAOB. Those standards require that

we plan and perform the audits to obtain reasonable

assurance about whether the consolidated financial

statements are free of material misstatement, whether

due to error or fraud. The Company is not required

to have, nor were we engaged to perform, an audit of its

internal control over financial reporting. As part

of our audits we are required to obtain an understanding

of internal control over financial reporting but not

for the purpose of expressing an opinion on the effectiveness

of the Company's internal control over

financial reporting. Accordingly,

we express no such opinion.

Our audits included

performing procedures to assess the risks of material

misstatement of the

consolidated financial statements, whether due to error

or fraud, and performing procedures that respond

to those risks. Such procedures included examining, on a test

basis, evidence regarding the amounts and

disclosures in the consolidated financial statements. Our

audits also included evaluating the accounting

principles used and significant estimates made by management,

as well as evaluating the overall

presentation of the consolidated financial statements. We

believe that our audits provide a reasonable

basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters

arising from the current period audit of the

financial statements that were communicated or required to

be communicated to the audit committee and

that: (1) relate to accounts

or disclosures that are material to the financial statements

and (2) involved our

especially challenging, subjective or complex judgments.

The communication of critical audit matters

does not alter in any way our opinion on the consolidated financial

statements, taken as a whole, and we

are not, by communicating the critical audit matters

below, providing

separate opinions on the critical

audit matters or on the accounts or disclosures to which

they relate.

Accounting for the effects of rate regulation

Description of the

Matter

As disclosed in note 7 of the consolidated financial statements,

the

Company has $2.6 billion in regulatory assets and $2.1 billion

in regulatory

liabilities. The Company’s rate-regulated subsidiaries

are subject to

regulation by various federal, state and provincial regulatory

authorities in

the geographic regions in which they operate. The regulatory

rates are

designed to recover the prudently incurred costs of providing

the regulated

products or services and provide a reasonable return

on the equity invested

or assets, as applicable. In addition to regulatory assets

and liabilities, rate

regulation impacts multiple financial statement line items,

including

property, plant and

equipment, operating revenues and expenses, income

taxes, and depreciation expense.

Auditing the impact of rate regulation on the Company’s

financial

statements is complex and highly judgmental due to the

significant

judgments made by the Company to support its accounting

and disclosure

for regulatory matters when final regulatory decisions or

orders have not yet

been obtained or when regulatory formulas are complex.

There is also

subjectivity involved in assessing the potential impact

of future regulatory

decisions on the financial statements. Although the Company

expects to

recover costs from customers through rates, there is a

risk that the regulator

will not approve full recovery of the costs incurred. The

Company’s

judgments include making an assessment of the probability

of recovery of

and recovery on costs incurred,

of the disallowance of part of the cost of

recently completed property,

plant and equipment and construction work in

progress, or of the probable refund to customers through future

rates.

How We Addressed

the Matter in Our

Audit

We performed audit procedures that included,

amongst others, assessing

the Company’s evaluation of the probability of

future recovery for regulatory

assets, property,

plant and equipment, and refund of regulatory liabilities by

obtaining and reviewing relevant regulatory orders, filings,

testimony,

hearings and correspondence, and other publicly available

information. For

regulatory matters for which regulatory decisions or orders

have not yet

been obtained, we inspected the rate-regulated subsidiaries’

filings for any

evidence that might contradict the Company’s assertions,

and reviewed

other regulatory orders, filings and correspondence for

other entities within

the same or similar jurisdictions to assess the likelihood

of recovery in

future rates based on the regulator’s treatment of similar costs

under similar

circumstances. We obtained and evaluated an

analysis from the Company

and corroborated that analysis with letters from legal counsel,

when

appropriate, regarding cost recoveries or future changes

in rates. We also

assessed the methodology,

accuracy and completeness of the Company’s

calculations of regulatory asset and liability balances based

on provisions

and formulas outlined in rate orders and other correspondence

with the

regulators. We evaluated the Company's disclosures

related to the impacts

of rate regulation.

Fair value measurement and disclosure of derivative financial

instruments

Description of the

Matter

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

and liabilities of

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

statements,

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

realized and unrealized losses during the year with respect

to HFT

derivatives.

Auditing the Company’s valuation of HFT derivatives

is complex and highly

judgmental due to the complexity of the contract terms

and valuation

models, and the significant estimation required in determining

the fair value

of the contracts. In determining the fair value of HFT

derivatives, significant

assumptions about future economic and market assumptions

with uncertain

outcomes are used, including third-party sourced forward commodity

pricing

curves based on illiquid markets, internally developed correlation

factors

and basis differentials, the Company’s own

credit risk and discount rates.

These assumptions have a significant impact on the fair

value of the HFT

derivatives.

How We Addressed

the Matter in Our

Audit

We performed audit procedures that included,

amongst others, reviewing

executed contracts and agreements for the identification of

inputs and

assumptions impacting the valuation of derivatives.

With the support of our

valuation specialists, we assessed the methodology and mathematical

accuracy of the Company’s valuation models and

compared the commodity

pricing curves, credit metrics and discount rates used by

the Company to

current market and economic data. For the forward commodity

pricing

curves, we compared the Company’s pricing curves

to independently

sourced pricing curves. We also assessed the

methodology and

mathematical accuracy of the Company’s calculations

to develop correlation

factors and basis differentials. In addition, we assessed

whether the fair

value hierarchy disclosures in note 16 to the consolidated financial

statements were consistent with the source of the significant

inputs and

assumptions used in determining the fair value of derivatives.

/s/ Ernst & Young

LLP

Chartered Professional Accountants

We have served as the Company‘s auditor since

1998.

Halifax, Canada

February 14, 2022

Emera Incorporated

Consolidated Statements of Income

For the

Year ended December 31

millions of Canadian dollars (except per share amounts)

2021

2020

Operating revenues

Regulated electric

4,665

4,442

Regulated gas

1,261

1,034

Non-regulated

(161)

Total

operating revenues (note 6)

5,765

5,506

Operating expenses

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

1,763

1,420

Regulated cost of natural gas

472

293

Non-regulated fuel for generation and purchased power

(1)

Operating, maintenance and general

1,369

1,419

Provincial, state, and municipal taxes

330

317

Depreciation and amortization

902

881

Impairment charges

Total

operating expenses

4,835

4,359

Income from operations

930

1,147

Income from equity investments (note 8)

143

149

Other income, net (note 9)

708

Interest expense, net

611

679

Income before provision for income taxes

555

1,325

Income tax (recovery) expense (note 10)

(6)

341

Net income

561

984

Non-controlling interest in subsidiaries

Preferred stock dividends

Net income attributable to common shareholders

510

938

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

Basic

257

248

Diluted

258

248

Earnings per common share (note 12)

Basic

1.98

3.78

Diluted

1.98

3.78

Dividends per common share declared

2.5750

2.4750

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

Emera Incorporated

Consolidated Statements of Comprehensive Income

For the

Year ended December 31

millions of Canadian dollars

2021

2020

Net income

561

984

Other comprehensive income (loss), net of tax

Foreign currency translation adjustment

(1)

(42)

(201)

Unrealized gains on net investment hedges

(2) (3)

Cash flow hedges

Net derivative gains

(4)

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

(1)

Net effects of cash flow hedges

Net change in unrecognized pension and post-retirement benefit obligation

(5)

124

(1)

Other comprehensive income (loss)

(6)

104

(174)

Comprehensive income

665

810

Comprehensive income attributable to non-controlling interest

Comprehensive Income of Emera Incorporated

664

809

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

Net of tax expense of $

million (2020 - $

million recovery) for the year ended December

31, 2021.

2) The Company has designated $

1.2

billion United States dollar denominated Hybrid

Notes as a hedge of the foreign currency

exposure of its net investment in United States

dollar denominated operations.

Net of tax expense of $

million (2020 - $

million expense) for the year ended December

31, 2021.

Net of tax expense of $

million (2020 -

nil

) for the year ended December 31, 2021.

Net of tax expense of $

million (2020 - $

million recovery) for the year ended December

31, 2021.

Net of tax expense of $

million (2020 - $

million expense) for the year ended December

31, 2021.

Emera Incorporated

Consolidated Balance Sheets

As at

December 31

millions of Canadian dollars

2021

2020

Assets

Current assets

Cash and cash equivalents

394

220

Restricted cash (note 32)

Inventory (note 14)

538

453

Derivative instruments (notes 15 and 16)

195

Regulatory assets (note 7)

253

165

Receivables and other current assets (note 18)

1,733

1,233

3,136

2,178

Property, plant and equipment,

net of accumulated depreciation

and amortization of $

8,739

and $

8,714

, respectively (note 20)

20,353

19,535

Other assets

Deferred income taxes (note 10)

295

209

Derivative instruments (notes 15 and 16)

106

Regulatory assets (note 7)

2,313

1,419

Net investment in direct financing lease (note 19)

462

475

Investments subject to significant influence (note 8)

1,382

1,346

Goodwill (note 22)

5,696

5,720

Other long-term assets

501

327

10,755

9,521

Total assets

34,244

31,234

Emera Incorporated

Consolidated Balance Sheets – Continued

As at

December 31

millions of Canadian dollars

2021

2020

Liabilities and Equity

Current liabilities

Short-term debt (note 23)

1,742

1,625

Current portion of long-term debt (note 25)

462

1,382

Accounts payable

1,485

1,148

Derivative instruments (notes 15 and 16)

533

251

Regulatory liabilities (note 7)

290

129

Other current liabilities (note 24)

366

340

4,878

4,875

Long-term liabilities

Long-term debt (note 25)

14,196

12,339

Deferred income taxes (note 10)

1,868

1,629

Derivative instruments (notes 15 and 16)

149

Regulatory liabilities (note 7)

1,765

1,832

Pension and post-retirement liabilities (note 21)

370

453

Other long-term liabilities (note 8 and 26)

868

781

19,216

17,121

Equity

Common stock (note 11)

7,242

6,705

Cumulative preferred stock (note 28)

1,422

1,004

Contributed surplus

Accumulated other comprehensive income (loss) (note 13)

(79)

Retained earnings

1,348

1,495

Total

Emera Incorporated equity

10,116

9,204

Non-controlling interest in subsidiaries

(note 29)

Total

equity

10,150

9,238

Total liabilities and equity

34,244

31,234

Commitments and contingencies

(note 27)

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

Approved on behalf of the Board of Directors

“M. Jacqueline Sheppard”

“Scott Balfour”

Chair of the Board

President and Chief Executive Officer

Emera Incorporated

Consolidated Statements of Cash Flows

For the

Year ended December 31

millions of Canadian dollars

2021

2020

Operating activities

Net income

561

984

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

Depreciation and amortization

915

899

Income from equity investments, net of dividends

(69)

(76)

Allowance for equity funds used during construction

(61)

(45)

Deferred income taxes, net

(37)

381

Net change in pension and post-retirement liabilities

(23)

Regulated fuel adjustment mechanism

(166)

(94)

Net change in fair value of derivative instruments

404

(36)

Net change in regulatory assets and liabilities

(176)

(87)

Net change in capitalized transportation capacity

(107)

Impairment charges

Gain on sale, excluding transaction costs

(603)

Other operating activities, net

Changes in non-cash working capital (note 30)

(152)

217

Net cash provided by operating activities

1,185

1,637

Investing activities

Additions to property, plant and equipment

(2,359)

(2,623)

Proceeds from dispositions (note 4)

1,401

Other investing activities

(2)

Net cash used in investing activities

(2,332)

(1,224)

Financing activities

Change in short-term debt, net

(155)

385

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

640

399

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

(377)

(688)

Proceeds from long-term debt, net of issuance costs

2,554

428

Retirement of long-term debt

(1,660)

(513)

Net proceeds (repayments) under committed credit facilities

(203)

Issuance of common stock, net of issuance costs

317

285

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

416

Dividends on common stock

(443)

(409)

Dividends on preferred stock

(50)

(45)

Other financing activities

(13)

(11)

Net cash provided by (used in) financing activities

1,311

(372)

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

(1)

(61)

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

163

(20)

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

254

274

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

417

254

Cash, cash equivalents and restricted cash consists of:

Cash

237

220

Short-term investments

157

Restricted cash

Cash, cash equivalents and restricted cash

417

254

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

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

Emera Incorporated

Consolidated Statements of Changes in Equity

Accumulated

Other

Comprehensive

Non-

Common

Preferred

Contributed

Income

Retained

Controlling

Total

Stock

Surplus

(Loss)

(1)

Earnings

Interest

Equity

millions of Canadian dollars

Balance, December 31, 2020

6,705

1,004

(79)

1,495

9,238

Net income of Emera

incorporated

560

561

Other comprehensive income,

net of tax expense of $

million

104

Dividends declared on preferred

stock (note 28)

(50)

Dividends declared on common

stock ($

2.575

0/share)

(657)

Issuance of preferred shares,

net of after-tax issuance costs

(note 28)

418

Common stock issued under

purchase plan

235

Issuance of common stock, net

of after-tax issuance costs

284

Senior management stock

options exercised

Other

(1)

Balance, December 31, 2021

7,242

1,422

1,348

10,150

Balance, December 31, 2019

6,216

1,004

1,173

8,601

Net income of Emera Inc

983

984

Other comprehensive loss, net of

tax expense of $

million

(174)

Dividends declared on preferred

stock (note 28)

(45)

Dividends declared on common

stock ($

2.4750

/share)

(609)

Common stock issued under

purchase plan

215

Issuance of common stock, net of

after-tax issuance costs

251

Senior management stock

options exercised

(1)

Adoption of credit losses

accounting standard

(7)

Other

(2)

Balance, December 31, 2020

6,705

1,004

(79)

1,495

9,238

(1) Accumulated Other Comprehensive Income (Loss)

("AOCI") ("AOCL")

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

Emera Incorporated

Notes to the Consolidated Financial Statements

As at December 31, 2021 and 2020

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Emera Incorporated (“Emera” or the “Company”) is an

energy and services company which invests in

electricity generation, transmission and distribution, and

gas transmission and distribution.

At December 31, 2021, Emera’s reportable segments

include the following:

●

Florida Electric Utility,

which consists of Tampa

Electric,

a vertically integrated regulated electric

utility, serving approximately

810,600

customers in West Central Florida;

●

Canadian Electric Utilities, which includes:

●

Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated

electric utility and the

primary electricity supplier in Nova Scotia, serving approximately

536,000

customers; and

●

Emera Newfoundland & Labrador Holdings Inc. (“ENL”),

consisting of two transmission

investments related to an

824

megawatt (“MW”) hydroelectric generating facility at

Muskrat

Falls on the Lower Churchill River in Labrador being developed

by Nalcor Energy.

ENL’s two

investments are:

●

100

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

which developed the

Maritime Link Project, a $

1.8

billion (including AFUDC) transmission project, including

two

170

-kilometre sub-sea cables, connecting the island

of Newfoundland and Nova

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

and

●

37.4

per cent investment in the partnership capital of

Labrador-Island Link Limited

Partnership (“LIL”), a $

3.7

billion electricity transmission project in Newfoundland

and

Labrador to enable the transmission of Muskrat Falls energy

between Labrador and

the island of Newfoundland. Construction of the LIL has

been completed and Nalcor

recognized the first flow of energy from Labrador to Newfoundland

in June 2018.

Muskrat Falls generators are completed and available fo

service and Nalcor is

forecasting it will achieve final commissioning of Muskrat

Falls and LIL in the first half

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

●

Other Electric Utilities, which includes Emera (Caribbean)

Incorporated (“ECI”), a holding company

with regulated electric utilities that include:

●

The Barbados Light & Power Company Limited (“BLPC”),

a vertically integrated regulated

electric utility on the island of Barbados, serving approximately

132,000

customers;

●

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

integrated regulated electric

utility on Grand Bahama Island, serving approximately

19,000

customers;

●

51.9

per cent interest in Dominica Electricity Services

Ltd. (“Domlec”), a vertically integrated

regulated electric utility on the island of Dominica, serving

approximately

35,700

customers;

and

●

19.5

per cent equity interest in St. Lucia Electricity Services

Limited (“Lucelec”), a vertically

integrated regulated electric utility on the island of St.

Lucia.

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

Maine which was previously included in the

Other Electric Utilities segment. Refer to note 4.

●

Gas Utilities and Infrastructure, which includes:

●

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

serving approximately

445,000

customers across Florida;

●

New Mexico Gas Company,

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

serving

approximately

542,000

customers in New Mexico;

●

SeaCoast Gas Transmission, LLC (“SeaCoast”),

a regulated intrastate natural gas

transmission company offering services in Florida;

●

Emera Brunswick Pipeline Company Limited (“Brunswick

Pipeline”), a

145

-kilometre pipeline

delivering re-gasified liquefied natural gas (“LNG”) from Saint

John, New Brunswick to the

United States border under a

-year firm service agreement with Repsol Energy

Canada,

which expires in 2034; and

●

12.9

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

1,400

-kilometre

pipeline, that transports natural gas throughout markets

in Atlantic Canada and the

northeastern United States.

●

Emera’s other reportable segment includes investments

in energy-related non-regulated companies

which includes:

●

Emera Energy, which

consists of:

●

Emera Energy Services (“EES”), a physical energy business

that purchases and sells

natural gas and electricity and provides related energy

asset management services;

●

Brooklyn Power Corporation (“Brooklyn Energy”), a

MW biomass co-generation

electricity facility in Brooklyn, Nova Scotia; and

●

50.0

per cent joint venture interest in Bear Swamp Power

Company LLC (“Bear

Swamp”), a

633

MW pumped storage hydroelectric facility in northwestern

Massachusetts.

●

Emera Reinsurance Limited, a captive insurance company providing

insurance and

reinsurance to Emera and certain affiliates;

●

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

Inc. (“TECO Finance”),

financing subsidiaries of Emera;

●

Emera Technologies

LLC, a wholly owned technology company focused on finding

ways to

deliver renewables and resilient energy to customers;

●

Emera US Holdings Inc., a wholly owned holding company

for certain of Emera’s assets

located in the United States; and

●

Other investments.

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

worldwide enacting emergency measures to

combat the spread of the virus. Management considered the

impact of COVID-19 in the Company’s

estimates and results and concluded the financial statements as

of and for the year ended December 31,

2021 were not materially impacted.

Basis of Presentation

These consolidated financial statements are prepared

and presented in accordance with United States

Generally Accepted Accounting Principles (“USGAAP”).

In the opinion of management, these

consolidated financial statements include all adjustments

that are of a recurring nature and necessary to

fairly state the financial position of Emera.

All dollar amounts are presented in Canadian dollars, unless

otherwise indicated.

Principles of Consolidation

The consolidated financial statements of Emera include

the accounts of Emera Incorporated, its majority-

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

in which Emera is the primary beneficiary.

For

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

equity method of accounting to record

investments in which the Company has the ability to exercise

significant influence, and for VIEs in which

Emera is not the primary beneficiary.

The Company performs ongoing analysis to assess whether

it holds any VIEs or whether any

reconsideration events have arisen with respect to existing

VIEs.

identify potential VIEs,

management reviews contractual and ownership arrangements

such as leases, long-term purchase

power agreements, tolling contracts, guarantees, jointly

owned facilities and equity investments. VIEs

of which the Company is deemed the primary beneficiary

must be consolidated. The primary

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

of the entity that most significantly

impacts its economic performance and the obligation to

absorb losses of the entity that could

potentially be significant to the entity.

In circumstances where Emera has an investment

in a VIE but

is not deemed the primary beneficiary,

the VIE is accounted for using the equity method.

Intercompany balances and transactions have been eliminated

on consolidation, except for the net profit

on certain transactions between certain non-regulated and regulated

entities in accordance with

accounting standards for rate-regulated entities. The net profit

on these transactions, which would be

eliminated in the absence of the accounting standards

for rate-regulated entities, is recorded in non-

regulated operating revenues. An offset is recorded

to property, plant

and equipment, regulatory assets,

regulated fuel for generation and purchased power,

or operating, maintenance and general (“OM&G”),

depending on the nature of the transaction.

Use of Management Estimates

The preparation of consolidated financial statements in accordance

with USGAAP requires management

to make estimates and assumptions. These may affect

the reported amounts of assets and liabilities at

the date of the financial statements and reported amounts

of revenues and expenses during the reporting

periods. Significant areas requiring the use of management

estimates relate to rate-regulated assets and

liabilities, accumulated reserve for cost of removal, pension

and post-retirement benefits, unbilled

revenue, useful lives for depreciable assets, goodwill,

and long-lived assets impairment assessments,

income taxes, asset retirement obligations, and valuation

of financial instruments. Management evaluates

the Company’s estimates on an ongoing basis based

upon historical experience, current and expected

conditions and assumptions believed to be reasonable

at the time the assumption is made, with any

adjustments recognized in income in the year they arise.

Management has analyzed the impact of the COVID-19 pandemic

on its estimates and assumptions and

concluded that no material adjustments were required

for the year ended December 31, 2021.

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

financial results and business operations

cannot be predicted at this time and will depend on future

developments, including the duration and

severity of the pandemic, timing and effectiveness

of vaccinations, further potential government actions

and future economic activity and energy usage. Actual

results may differ significantly from these

estimates.

Regulatory Matters

Regulatory accounting applies where rates are established

by, or subject to

approval by, an

independent

third-party regulator. The rates

are designed to recover prudently incurred costs of

providing the regulated

products or services and provide an opportunity for a reasonable

rate of return on invested capital, as

applicable. For further detail, refer to note 7.

Foreign Currency Translation

Monetary assets and liabilities denominated in foreign

currencies are converted to Canadian dollars at the

rates of exchange prevailing at the balance sheet date. The resulting

differences between the translation

at the original transaction date and the balance sheet

date are included in income.

Assets and liabilities of foreign operations whose functional

currency is not the Canadian dollar are

translated using the exchange rates in effect at the

balance sheet date and the results of operations

the average exchange rate in effect for the

period. The resulting exchange gains and losses on the assets

and liabilities are deferred on the balance sheet in AOCI.

The Company designates certain United States dollar

denominated debt held in Canadian dollar

functional currency companies as hedges of net investments

in United States dollar denominated foreign

operations. The change in the carrying amount of these

investments, measured at the exchange rates in

effect at the balance sheet date is recorded in

Other Comprehensive Income (“OCI”).

Revenue Recognition

Regulated Electric Revenue

Electric revenues, including energy charges, demand charges,

basic facilities charges and clauses and

riders, are recognized when obligations under the terms

of a contract are satisfied, which is when

electricity is delivered to customers over time as the customer

simultaneously receives and consumes the

benefits of the electricity.

Electric revenues are recognized on an accrual basis and include

billed and

unbilled revenues. Revenues related to the sale of electri

city are recognized at rates approved by the

respective regulator and recorded based on metered usage, which

occurs on a periodic, systematic

basis, generally monthly or bi-monthly.

At the end of each reporting period, the electricity delivered

customers, but not billed, is estimated and the corresponding

unbilled revenue is recognized. The

Company’s estimate of unbilled revenue at the

end of the reporting period is calculated by estimating the

number of megawatt hours (“MWh”) delivered to customers

at the established rates expected to prevail in

the upcoming billing cycle. This estimate includes assumptions

as to the pattern of energy demand,

weather, line losses and inter-period

changes to customer classes.

Regulated Gas Revenue

Gas revenues, including energy charges, demand charges,

basic facilities charges and applicable

clauses and riders, are recognized when obligations under the

terms of a contract are satisfied, which is

when gas is delivered to customers over time as the customer

simultaneously receives and consumes the

benefits of the gas. Gas revenues are recognized on an

accrual basis and include billed and unbilled

revenues. Revenues related to the distribution and sale

of gas are recognized

at rates approved by the

respective regulator and recorded based on metered usage, which

occurs on a periodic, systematic

basis, generally monthly.

At the end of each reporting period, the gas delivered to

customers, but not

billed, is estimated and the corresponding unbilled revenue

is recognized. The Company’s estimate of

unbilled revenue at the end of the reporting period is calculated

by estimating the number of therms

delivered to customers at the established rates expected

to prevail in the upcoming billing cycle. This

estimate includes assumptions as to the pattern of usage,

weather, and inter-period

changes to customer

classes.

Non-regulated Revenue

Marketing and trading margins are comprised of Emera

Energy’s corresponding purchases and sales

natural gas and electricity,

pipeline capacity costs and energy asset management revenues.

Revenues

are recorded when obligations under terms of a contract

are satisfied and are presented on a net basis,

reflecting the nature of the contractual relationships with

customers and suppliers.

Energy sales are recognized when obligations under the

terms of the contracts are satisfied, which is

when electricity is delivered to customers over time.

Other non-regulated revenues are recorded when obligations

under terms of a contract are satisfied.

Other

Sales, value add, and other taxes, except for gross receipts taxes

discussed below, collected

by the

Company concurrent with revenue-producing activities

are excluded from revenue.

Leases

The Company determines whether a contract contains

a lease at inception by evaluating if the contract

conveys the right to control the use of an identified asset for a

period of time in exchange for

consideration.

Emera has leases with independent power producers (“IPP”)

and other utilities with annual requirements

to purchase wind and hydro energy over varying contract

lengths that are classified as finance leases.

These finance leases are not recorded on the Company’s

Consolidated Balance Sheets as payments

associated with the leases are variable in nature and there

are no minimum fixed lease payments. Lease

expense associated with these leases is recorded as “Regulated

fuel for generation and purchased

power” on the Consolidated Statements of Income.

Operating lease liabilities and right-of-use (“ROU”) assets

are recognized on the Consolidated Balance

Sheets based on the present value of the future minimum lease

payments over the lease term at

commencement date. As most of Emera’s leases

do not provide an implicit rate, the incremental

borrowing rate at commencement of the lease is used

in determining the present value of future lease

payments. Lease expense is recognized on a straight-line

basis over the lease term and is recorded as

“Operating, maintenance and general” on the Consolidated

Statements of Income.

Where the Company is the lessor,

a lease is a sales-type lease if certain criteria are met

and the

arrangement transfers control of the underlying asset

to the lessee. For arrangements where the criteria

are met due to the presence of a third-party residual value

guarantee, the lease is a direct financing

lease.

For direct finance leases, a net investment in the lease

is recorded that consists of the sum of the

minimum lease payments and residual value (net of estimated

executory costs and unearned income).

The difference between the gross investment

and the cost of the leased item is recorded as unearned

income at the inception of the lease. Unearned income

is recognized in income over the life of the lease

using a constant rate of interest equal to the internal

rate of return on the lease.

For sales-type leases, the accounting is similar to the accounting

for direct finance leases, however the

difference between the fair value and the carrying value

of the leased item is recorded at lease

commencement rather than deferred over the term of the

lease.

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

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

Franchise Fees and Gross Receipts

Tampa

Electric and PGS recover from customers certain costs

incurred, on a dollar-for-dollar basis,

through prices approved by the Florida Public Service Commission

(“FPSC”). The amounts included in

customers’ bills for franchise fees and gross receipt taxes

are included as “Regulated electric” and

“Regulated gas” revenues in the Consolidated Statements

of Income. Franchise fees and gross receipt

taxes payable by Tampa

Electric and PGS are included as an expense on the Consolidated

Statements

of Income in “Provincial, state and municipal taxes”.

NMGC is an agent in the collection and payment of franchise

fees and gross receipt taxes and is not

required by a tariff to present the amounts on

a gross basis. Therefore, NMGC’s franchise

fees and gross

receipt taxes are presented net with no line item impact

on the Consolidated Statements of Income.

Property, Plant and

Equipment

Property, plant and

equipment are recorded at original cost, including

allowance for funds used during

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

received in aid of construction.

The cost of additions, including betterments and replacements

of units of property,

plant and equipment,

are included in “Property,

plant and equipment”. When units of regulated property,

plant and equipment

are replaced, renewed or retired, their cost plus removal or

disposal costs, less salvage proceeds, is

charged to accumulated depreciation, with no gain or loss

reflected in income. Where a disposition of

non-regulated property,

plant and equipment occurs, gains and losses are

included in income as the

dispositions occur.

The cost of property,

plant and equipment represents the original cost of

materials, contracted services,

direct labour, AFUDC for regulated

property or interest for non-regulated property,

asset retirement

obligations (“ARO”), and overhead attributable to the capital

project. Overhead includes corporate costs

such as finance, information technology and labour costs,

along with other costs related to support

functions, employee benefits, insurance, procurement,

and fleet operating and maintenance.

Expenditures for project development are capitalized if

they are expected to have a future economic

benefit.

Normal maintenance projects are expensed as incurred.

Planned major maintenance projects that do not

increase the overall life of the related assets are expensed.

When a major maintenance project increases

the life or value of the underlying asset, the cost is capitalized.

Depreciation is determined by the straight-line method, based

on the estimated remaining service lives of

the depreciable assets in each functional class of depreciable

property. For some

of Emera’s rate-

regulated subsidiaries, depreciation is calculated using

the group remaining life method, which is applied

to the average investment, adjusted for anticipated costs

of removal less salvage, in functional classes of

depreciable property.

The service lives of regulated assets require

the appropriate regulatory approval.

Intangible assets, which are included in “Property,

plant and equipment,” consist primarily of computer

software and land rights. Amortization is determined

by the straight-line method, based on the estimated

remaining service lives of the asset in each category.

For some of Emera’s rate-regulated subsidiaries,

amortization is calculated using the amortizable life method

which is applied to the net book value to date

over the remaining life of those assets. The service lives

of regulated intangible assets require regulatory

approval.

Goodwill

Goodwill is calculated as the excess of the purchase price

of an acquired entity over the estimated fair

values of identifiable assets acquired and liabilities assumed

at the acquisition date. Goodwill is carried at

initial cost less any write-down for impairment and is adjusted

for the impact of foreign exchange. Under

the applicable accounting guidance, goodwill is subject

to assessment for impairment at the reporting unit

level annually, or if

an event or change in circumstances indicates that the

fair value of a reporting unit

may be below its carrying value. For further detail, refer

to note 22.

Income Taxes and

Investment Tax

Credits

Emera recognizes deferred income tax assets and liabilities

for the future tax consequences of events

that have been included in the financial statements or income tax

returns. Deferred income tax assets

and liabilities are determined based on the difference

between the carrying value of assets and liabilities

on the Consolidated Balance Sheets, and their respective

tax bases using enacted tax rates in effect for

the year in which the differences are expected to

reverse. The effect of a change in income tax

rates on

deferred income tax assets and liabilities is recognized

in earnings in the period when the change is

enacted, unless required to be offset to a regulatory

asset or liability by law or by order of the regulator.

Emera recognizes the effect of income tax positions

only when it is more likely than not that they will be

realized. Management reviews all readily available current and

historical information, including forward-

looking information, and the

likelihood that deferred tax assets will be recovered from future

taxable

income is assessed and assumptions about the expected

timing of the reversal of deferred tax assets and

liabilities are made. If management subsequently determines

that it is likely that some or all of a deferred

income tax asset will not be realized, then a valuation allowance

is recorded to reflect the amount of

deferred income tax asset expected to be realized.

Generally, investment

tax credits are recorded as a reduction to income

tax expense in the current or

future periods to the extent that realization of such benefit

is more likely than not. Investment tax credits

earned by Tampa

Electric, PGS and NMGC on regulated assets are

deferred and amortized over the

estimated service lives of the related properties, as required

by regulatory practices.

Tampa

Electric, PGS, NMGC,

BLPC and Domlec collect income taxes from customers

based on current

and deferred income taxes. NSPI, ENL and Brunswick Pipeline

collect income taxes from customers

based on income tax that is currently payable except for

the deferred income taxes on certain regulatory

balances specifically prescribed by the regulator.

For the balance of regulated deferred income taxes,

NSPI, ENL and Brunswick Pipeline recognize regulatory

assets or liabilities where the deferred income

taxes are expected to be recovered from or returned to

customers in future years. These regulated assets

or liabilities are grossed up using the respective income

tax rate to reflect the income tax associated with

future revenues that are required to fund these deferred

income tax liabilities, and the income tax benefits

associated with reduced revenues resulting from the realization

of deferred income tax assets. GBPC is

not subject to income taxes.

Emera classifies interest and penalties associated with unrecognized

tax benefits as interest and

operating expense, respectively.

For further information, refer to note 10.

Derivatives and Hedging Activities

The Company manages its exposure to normal operating and

market risks relating to commodity prices,

foreign exchange, interest rates and share prices through

contractual protections with counterparties

where practicable, and by using financial instruments consisting

mainly of foreign exchange forwards and

swaps, interest rate options and swaps, equity derivatives,

and coal, oil and gas futures, options, forwards

and swaps. In addition, the Company has contracts for

the physical purchase and sale of natural gas.

These physical and financial contracts are classified as

held-for-trading (“HFT”). Collectively,

these

contracts and financial instruments are considered derivatives.

The Company recognizes the fair value of all its derivatives

on its balance sheet, except for non-financial

derivatives that meet the normal purchases and normal sales

(“NPNS”) exception. Physical contracts that

meet the NPNS exception are not recognized on the balance

sheet; these contracts are recognized in

income when they settle. A physical contract generally

qualifies for the NPNS exception if the transaction

is reasonable in relation to the Company’s business

needs, the counterparty owns or controls resources

within the proximity to allow for physical delivery,

the Company intends to receive physical delivery of the

commodity, and the

Company deems the counterparty creditworthy.

The Company continually assesses

contracts designated under the NPNS exception and will discontinue

the treatment of these contracts

under this exemption where the criteria are no longer met.

Derivatives qualify for hedge accounting if they meet stringent

documentation requirements and can be

proven to effectively hedge the identified risk both

at the inception and over the term of the instrument.

Specifically, for cash

flow hedges, the change in the fair value of derivatives is

deferred to AOCI and

recognized in income in the same period the related hedged

item is realized. Where the documentation or

effectiveness requirements are not met, the derivatives

are recognized at fair value with any changes in

fair value recognized in net income in the reporting period,

unless deferred as a result of regulatory

accounting.

Derivatives entered into by NSPI, NMGC and GBPC that

are documented as economic hedges or for

which the NPNS exception has not been taken, are subject

to regulatory accounting treatment. The

change in fair value of the derivatives is deferred to a

regulatory asset or liability.

The gain or loss is

recognized in the hedged item when the hedged item

is settled. Management believes any gains or

losses resulting from settlement of these derivatives related

to fuel for generation and purchased power

will be refunded to or collected from customers in future

rates. Tampa

Electric and PGS have no

derivatives related to hedging as a result of a FPSC approved

five-year moratorium on hedging of natural

gas purchases which ends on December 31, 2022. Tampa

Electric’s moratorium on hedging of natural

gas purchases will continue through December 31, 2024,

as a result of Tampa

Electric’s 2021 rate case

settlement agreement.

Derivatives that do not meet any of the above criteria are designated

as HFT,

with changes in fair value

normally recorded in net income of the period. The Company

has not elected to designate any derivatives

to be included in the HFT category where another accounting

treatment would apply.

Emera classifies gains and losses on derivatives as a component

of fuel for generation and purchased

power, other expenses, inventory,

OM&G and property,

plant and equipment, depending on the nature of

the item being economically hedged. Tran

sportation capacity arising as a result of marketing and

trading

derivative transactions is recognized as an asset in “Receivables

and other current assets” and amortized

over the period of the transportation contract term. Cash

flows from derivative activities are presented in

the same category as the item being hedged within

operating or investing activities on the Consolidated

Statements of Cash Flows. Non-hedged derivatives are included

in operating cash flows on the

Consolidated Statements of Cash Flows.

Derivatives, as reflected on the Consolidated Balance Sheets,

are not offset by the fair value amounts of

cash collateral with the same counterparty.

Rights to reclaim cash collateral are recognized

“Receivables and other current assets” and obligations

to return cash collateral are recognized in

“Accounts payable”.

Cash, Cash Equivalents and Restricted Cash

Cash equivalents consist of highly liquid short-term investments

with original maturities of three months or

less at acquisition.

Receivables and Allowance for Credit Losses

Utility customer receivables are recorded at the invoiced amount

and do not bear interest. Standard

payment terms for electricity and gas sales are approximately

30 days. A late payment fee may be

assessed on account balances after the due date.

The Company is exposed to credit risk with respect to

amounts receivable from customers. Credit

assessments may be conducted on new customers. Deposits

are requested on accounts in accordance

with the Company’s policy.

The Company also maintains provisions for expected credit losses,

which are

assessed on a regular basis.

Management estimates credit losses related to accounts

receivable after considering historical loss

experience, customer deposits, current events, the characteristics

of existing accounts and reasonable

and supportable forecasts that affect the collectability

of the reported amount. Provisions for credit losses

on receivables are expensed to maintain the allowance at a

level considered adequate to cover expected

losses. Receivables are written off against the

allowance when they are deemed uncollectible.

The economic impact of COVID-19 in the service territories

in which Emera operates, has impacted the

aging of customer receivables resulting in higher allowances

for credit losses related to customer

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

Inventory

Fuel and materials inventories are valued using the weighted

-average cost method. These inventories are

carried at the lower of weighted-average cost or net realizable

value, unless evidence indicates that the

weighted-average cost will be recovered in future customer

rates.

Asset Impairment

Long-Lived Assets

Emera assesses whether there has been an impairment

of long-lived assets and intangibles when a

triggering event occurs, such as a significant market disruption

or sale of a business.

The assessment involves comparing the undiscounted expected

future cash flows to the carrying value of

the asset. When the undiscounted cash flow analysis indicates

a long-lived asset is not recoverable, the

amount of the impairment loss is determined by measuring

the excess of the carrying amount of the long-

lived asset over its estimated fair value. The Company’s

assumptions relating to future results of

operations or other recoverable amounts, are based

on a combination of historical experience,

fundamental economic analysis, observable market activity

and independent market studies. The

Company’s expectations regarding uses and holding

periods of assets are based on internal long-term

budgets and projections, which consider external factors

and market forces, as of the end of each

reporting period. The assumptions made are consistent

with generally accepted industry approaches and

assumptions used for valuation and pricing activities.

Management considered whether the potential impacts

of the COVID-19 pandemic on undiscounted

future cash flows could indicate that long-lived assets

are not recoverable. As at December 31, 2021,

there are no indications of impairment of Emera’s

long-lived assets.

No impairment charges were recognized during the year

ended December 31, 2021. In 2020, impairment

charges of $

million ($

million after tax) were recognized on certain assets and

recorded in

“Impairment charges” in the Consolidated Statements of Income.

Goodwill

Goodwill is not amortized but is subject to an annual assessment

for impairment at the reporting unit level

with interim impairment tests performed when impairment

indicators are present. Reporting units are

generally determined at the operating segment level or one

level below the operating segment level.

Reporting units with similar characteristics are grouped

for the purpose of determining impairment, if any,

of goodwill.

When assessing goodwill for impairment the Company

has the option of first performing a

qualitative assessment to determine whether a quantitative

assessment is necessary.

In performing a

qualitative assessment management considers, among other

factors, macroeconomic conditions, industry

and market considerations and overall financial performance.

If the Company performs the qualitative assessment and

determines that it is more likely than not that its

fair value is less than its carrying amount, or if the Company

chooses to bypass the qualitative

assessment, a quantitative test is performed. The quantitative

test compares the fair value of the

reporting unit to its carrying amount, including goodwill.

If the carrying amount of the reporting unit

exceeds its fair value, an impairment loss is recorded as

a reduction to goodwill and a charge to operating

expense. Management estimates the fair value of the reporting

unit by using the income approach, or a

combination of the income and market approach. The income

approach is applied using a discounted

cash flow analysis which relies on management’s

best estimate of the reporting units’ projected

cash

flows. The analysis includes an estimate of terminal values

based on these expected cash flows using a

methodology which derives a valuation using an assumed

perpetual annuity based on the reporting unit’s

residual cash flows. The discount rate used is a market participant

rate based on a peer group of publicly

traded comparable companies and represents the weighted

average cost of capital of comparable

companies. When using the market approach, management

estimates fair value based on comparable

companies and transactions within the utility industry.

Significant assumptions used in estimating the fair

value include discount and growth rates, rate case assumptions,

valuation of the reporting units' net

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

and transactions, projected operating and

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

in assumptions described above could

result in a future material impairment of the goodwill assigned

to Emera’s reporting units with goodwill. As

part of the goodwill impairment assessment management considered

the potential impacts of the COVID-

19 pandemic on the future earnings of the reporting units.

As of December 31, 2021, $

5.6

billion of Emera’s goodwill was related to TECO

Energy (Tampa

Electric,

PGS and NMGC reporting units). Qualitative assessments

were performed for these reporting units given

the significant excess of fair value over carrying amounts

calculated during the last quantitative test in Q4

Management concluded it was more likely than not that

the fair value of these reporting units

exceeded their respective carrying amounts, including

goodwill. As such, no quantitative testing was

required.

As of December 31, 2021, $

million of Emera’s goodwill was related to GBPC.

In Q4 2021, the

Company performed a quantitative impairment assessment

for GBPC as this reporting unit is more

sensitive to changes in assumptions due to limited excess

of fair value over the carrying value. The

assessment estimated that the fair value of the reporting

unit exceeded its carrying value, including

goodwill, by approximately

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

Equity Method Investments

The carrying value of investments accounted for under

the equity method are assessed for impairment by

comparing the fair value of these investments to their carrying

values, if a fair value assessment was

completed, or by reviewing for the presence of impairment

indicators, including the impact of COVID-19. If

an impairment exists, and it is determined to be other-than-temporary,

a charge is recognized in earnings

equal to the amount the carrying value exceeds the investment’s

fair value. No impairment of equity

method investments was required in either 2021 or 2020.

Financial Assets

Equity investments, other than those accounted for under

the equity method of accounting, are measured

at fair value, with changes in fair value recognized in the

Consolidated Statements of Income. Equity

investments that do not have readily determinable fair

values are recorded at cost minus impairment, if

any, plus or minus

changes resulting from observable price changes

in orderly transactions for the

identical or similar investments. No impairment of financial

assets was required in either 2021 or 2020.

Asset Retirement Obligations

An ARO is recognized if a legal obligation exists in connection

with the future disposal or removal costs

resulting from the permanent retirement, abandonment

or sale of a long-lived asset. A legal obligation

may exist under an existing or enacted law or statute,

written or oral contract, or by legal construction

under the doctrine of promissory estoppel.

An ARO represents the fair value of the estimated cash

flows necessary to discharge the future

obligation, using the Company’s credit adjusted

risk-free rate. The amounts are reduced by actual

expenditures incurred. Estimated future cash flows are based

on completed depreciation studies,

remediation reports, prior experience, estimated useful

lives and governmental regulatory requirements.

The present value of the liability is recorded and the carrying

amount of the related long-lived asset is

correspondingly increased. The amount capitalized at inception

is depreciated in the same manner as the

related long-lived asset. Over time, the liability is accreted to

its estimated future value. AROs are

included in “Other long-term liabilities” and accretion

expense is included as part of “Depreciation and

amortization”. Any regulated accretion expense not yet

approved by the regulator is recorded in

“Property, plant and equipment”

and included in the next depreciation study.

Some of the Company’s transmission and distribution

assets may have conditional AROs which are not

recognized in the consolidated financial statements as

the fair value of these obligations could not be

reasonably estimated, given there is insufficient information

to do so. A conditional ARO refers to a legal

obligation to perform an asset retirement activity in which

the timing and/or method of settlement are

conditional on a future event that may or may not be

within the control of the entity.

Management

monitors these obligations and a liability is recognized at fair

value in the period in which an amount can

be determined.

Cost of Removal

Tampa

Electric, PGS, NMGC and NSPI recognize non-ARO

costs of removal (“COR”) as regulatory

liabilities. The non-ARO COR represent funds received

from customers through depreciation rates to

cover estimated future non-legally required COR of property,

plant and equipment upon retirement. The

companies accrue for COR over the life of the related

assets based on depreciation studies approved by

their respective regulators. The costs are estimated based

on historical experience and future

expectations, including expected timing and estimated

future cash outlays.

Stock-Based Compensation

The Company has several stock-based compensation

plans: a common share option plan for senior

management; an employee common share purchase plan;

a deferred share unit (“DSU”) plan; a

performance share unit (“PSU”) plan; and a restricted

share unit (“RSU”) plan. The Company accounts for

its plans in accordance with the fair value based method of

accounting for stock-based compensation.

Stock-based compensation cost is measured at the grant date,

based on the calculated fair value of the

award, and is recognized as an expense over the employee’s

or director’s requisite service period using

the graded vesting method. Stock-based compensation

plans recognized as liabilities are initially

measured at fair value and re-measured at fair value at

each reporting date, with the change in liability

recognized in income.

Employee Benefits

The costs of the Company’s pension and other

post-retirement benefit programs for employees are

expensed over the periods during which employees render service.

The Company recognizes the funded

status of its defined-benefit and other post-retirement plans on

the balance sheet and recognizes

changes in funded status in the year the change occurs.

The Company recognizes the unamortized gains

and losses and past service costs in AOCI or regulatory

assets. The components of net periodic benefit

cost other than the service cost component are included

in “Other income, net” on the Consolidated

Statements of Income.

CHANGE IN ACCOUNTING POLICY

The new USGAAP accounting policies that are applicable to,

and adopted by the Company in 2021, are

described as follows:

Accounting for Convertible Instruments and Contracts

in an Entity’s Own Equity

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

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

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

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

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

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

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

standard.

Guaranteed Debt Securities Disclosure Requirements

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

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

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

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

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

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

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

Management’s Discussion & Analysis.

FUTURE ACCOUNTING PRONOUNCEMENTS

The Company considers the applicability and impact of

all ASUs issued by the Financial Accounting

Standards Board (“FASB”). The

ASUs that have been issued by FASB,

but are not yet effective, were

assessed and determined to be either not applicable

to the Company or have an insignificant impact on

the consolidated financial statements.

DISPOSITIONS

On March 24, 2020, Emera completed the sale of

Emera Maine

for a total enterprise value of

approximately $

2.0

billion including cash proceeds of $

1.4

billion, transferred debt and working capital

adjustments. A gain on disposition of $

585

million ($

309

million after tax) net of transaction costs, was

recognized in the Other segment and included in “Other

income” on the Consolidated Statements of

Income.

SEGMENT INFORMATION

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

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

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

operating decision maker.

Emera’s

five

reportable segments are Florida Electric Utility,

Canadian Electric

Utilities, Other Electric Utilities, Gas Utilities and Infrastructure,

and Other.

Florida

Canadian

Other

Gas Utilities

Inter-

Electric

and

Segment

millions of Canadian dollars

Utility

Utilities

Infrastructure

Other

Eliminations

Total

For the year ended December 31, 2021

Operating revenues from

external customers (1)

2,718

1,501

445

1,276

(175)

5,765

Inter-segment revenues

(1)

(28)

Total operating revenues

2,724

1,501

445

1,280

(157)

(28)

5,765

Regulated fuel for generation

and purchased power

894

654

218

(3)

1,763

Regulated cost of natural gas

472

OM&G

536

291

140

325

(16)

1,369

Depreciation and amortization

469

246

121

902

Income from equity investments

103

143

AFUDC - debt and equity

Interest expense, net

138

132

269

611

Internally allocated interest (2)

(13)

Income tax expense (recovery)

(150)

(6)

Net income (loss) attributable to

common shareholders

462

241

198

(412)

510

Capital expenditures

1,331

366

111

515

2,328

As at December 31, 2021

Total assets

17,903

7,418

1,402

6,666

2,034

(1,179)

(3)

34,244

Investments subject to

significant influence

1,215

123

1,382

Goodwill

4,436

1,189

5,696

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

transactions have been eliminated on consolidation

except for certain

transactions between non-regulated and regulated entities

that have not been eliminated because management

believes the

elimination of these transactions would understate

property, plant and equipment, OM&G expenses, or regulated fuel for

generation

and purchased power. Inter-company transactions that have not been

eliminated are measured at the amount of

consideration

established and agreed to by the related parties.

Eliminated transactions are included in determining

reportable segments.

(2) Segment net income is reported on a basis

that includes internally allocated financing

costs.

(3) Primarily relates to consolidated deferred tax reclassifications.

Deferred tax assets are reclassified and

netted with deferred tax

liabilities upon consolidation.

Florida

Canadian

Other

Gas Utilities

Inter-

Electric

and

Segment

millions of Canadian dollars

Utility

Utilities

Infrastructure

Other

Eliminations

Total

For the year ended December 31, 2020

Operating revenues from

external customers

(1)

2,473

1,494

474

1,051

5,506

Inter-segment revenues

(1)

(29)

Total operating revenues

2,480

1,494

474

1,058

(29)

5,506

Regulated fuel for generation

and purchased power

574

659

194

(7)

1,420

Regulated cost of natural gas

293

OM&G

552

282

151

334

115

(15)

1,419

Depreciation and amortization

455

236

111

881

Income from equity investments

149

AFUDC - debt and equity

Interest expense, net

151

139

301

679

Internally allocated interest (2)

(13)

Gain on sale, net of

transactions costs

585

Impairment charges

(25)

Income tax expense (recovery)

(8)

192

341

Net income attributable to

common shareholders

501

221

162

938

Capital expenditures

1,361

338

148

749

2,600

As at December 31, 2020

Total assets

16,889

6,752

1,365

6,067

1,234

(1,073)

(3)

31,234

Investments subject to

significant influence

1,176

129

1,346

Goodwill

4,455

1,194

5,720

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

transactions have been eliminated on consolidation

except for certain

transactions between non-regulated and regulated entities

that have not been eliminated because management

believes the

elimination of these transactions would understate

property, plant and equipment, OM&G expenses, or regulated fuel for

generation

and purchased power. Inter-company transactions that have not been

eliminated are measured at the amount of

consideration

established and agreed to by the related parties.

Eliminated transactions are included in determining

reportable segments.

(2) Segment net income is reported on a basis

that includes internally allocated financing costs.

(3) Primarily relates to consolidated deferred tax reclassifications.

Deferred tax assets are reclassified and

netted with deferred tax

liabilities upon consolidation.

Geographical Information

Revenues

(based on country of origin of the product

or service sold)

For the

Year ended December 31

millions of Canadian dollars

2021

2020

United States

3,754

3,522

Canada

1,566

1,569

Barbados

292

263

The Bahamas

110

112

Dominica

5,765

5,506

Property Plant and Equipment:

As at

December 31

millions of Canadian dollars

2021

2020

United States

14,978

14,353

Canada

4,440

4,304

Barbados

535

510

The Bahamas

322

289

Dominica

20,353

19,535

REVENUE

The following disaggregates the Company’s revenue

by major source:

Florida

Canadian

Other

Gas Utilities

Inter-

Electric

and

Segment

millions of Canadian dollars

Utility

Utilities

Infrastructure

Other

Eliminations

Total

For the year ended December 31, 2021

Regulated Electric Revenue

Residential

1,449

797

165

2,411

Commercial

754

407

232

1,393

Industrial

215

237

478

Other electric and regulatory

deferrals

289

323

Other (1)

(6)

Regulated electric revenue

2,724

1,501

445

(6)

4,665

Regulated Gas Revenue

Residential

642

Commercial

379

Industrial

(2)

Finance income (2)(3)

Other

121

(2)

119

Regulated gas revenue

1,265

(4)

1,261

Non-Regulated

Marketing and trading margin (4)

102

Energy sales

(21)

Other

Mark-to-market (3)

(289)

(286)

Non-regulated revenue

(157)

(18)

(161)

Total operating revenues

2,724

1,501

445

1,280

(157)

(28)

5,765

(1) Other includes rental revenues, which do not

represent revenue from contracts with customers.

(2) Revenue related to Brunswick Pipeline's service agreement

with Repsol Energy Canada.

(3) Revenue which does not represent revenues

from contracts with customers.

(4) Includes gains (losses) on settlement of energy

related derivatives, which do not represent

revenue from contracts with

customers.

Florida

Canadian

Other

Gas Utilities

Inter-

Electric

and

Segment

millions of Canadian dollars

Utility

Utilities

Infrastructure

Other

Eliminations

Total

For the year ended December 31, 2020

Regulated Electric Revenue

Residential

1,365

806

179

2,350

Commercial

678

405

233

1,316

Industrial

178

224

434

Other electric and regulatory

deferrals

242

281

Other (1)

(7)

Regulated electric revenue

2,480

1,494

474

(7)

4,442

Regulated Gas Revenue

Residential

495

Commercial

275

Industrial

Finance income (2)(3)

Other

156

(7)

149

Regulated gas revenue

1,041

(7)

1,034

Non-Regulated

Marketing and trading margin (4)

Energy sales

(16)

Other

Mark-to-market (3)

(46)

(45)

Non-regulated revenue

(15)

Total operating revenues

2,480

1,494

474

1,058

(29)

5,506

(1) Other includes rental revenues, which do not

represent revenue from contracts with customers.

(2) Revenue related to Brunswick Pipeline's service agreement

with Repsol Energy Canada.

(3) Revenue which does not represent revenues

from contracts with customers.

(4) Includes gains (losses) on settlement of energy

related derivatives, which do not represent

revenue from contracts with

customers.

Remaining Performance Obligations

Remaining performance obligations primarily represent

gas transportation contracts, lighting contracts

and long-term steam supply arrangements with fixed contract

terms. As of December 31, 2021, the

aggregate amount of the transaction price allocated to

remaining performance obligations was $

437

million (2020 – $

464

million). This amount includes $

142

million of future performance obligations related

to a gas transportation contract between SeaCoast and PGS

through 2040. This amount excludes

contracts with an original expected length of one year

or less and variable amounts for which Emera

recognizes revenue at the amount to which it has the right

to invoice for services performed. Emera

expects to recognize revenue for the remaining performance

obligations through

2041

REGULATORY

ASSETS AND LIABILITIES

Regulatory assets represent prudently incurred costs that have

been deferred because it is probable they

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

Management believes existing

regulatory assets are probable for recovery either because

the Company received specific approval from

the applicable regulator, or

due to regulatory precedent established for similar circumstanc

es. If

management no longer considers it probable that an asset

will be recovered, the deferred costs are

charged to income.

Regulatory liabilities represent obligations to make refunds

to customers or to reduce future revenues for

previous collections. If management no longer considers

it probable that a liability will be settled, the

related amount is recognized in income.

For regulatory assets and liabilities that are amortized, the amortization

is as approved by the respective

regulator.

As at

December 31

millions of Canadian dollars

2021

2020

Regulatory assets

Deferred income tax regulatory assets

1,045

887

Tampa

Electric capital cost recovery for early retired assets

657

Pension and post-retirement medical plan

291

394

Regulated fuel adjustment mechanism

145

NMGC winter event gas cost recovery

117

Cost recovery clauses

114

Storm restoration regulatory asset

Environmental remediations

Stranded cost recovery

Deferrals related to derivative instruments

Demand side management ("DSM") deferral

Unamortized defeasance costs

Other

2,566

1,584

Current

253

165

Long-term

2,313

1,419

Total

regulatory assets

2,566

1,584

Regulatory liabilities

Deferred income tax regulatory liabilities

863

933

Accumulated reserve - cost of remova

819

865

Deferrals related to derivative instruments

241

Storm reserve

Cost recovery clauses

Self-insurance fund (note 32)

Regulated fuel adjustment mechanism

Other

2,055

1,961

Current

290

129

Long-term

1,765

1,832

Total

regulatory liabilities

2,055

1,961

Deferred Income Tax

Regulatory Assets and Liabilities

the extent deferred income taxes are expected to be recovered

from or returned to customers in future

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

Tampa Electric Capital

Cost Recovery for Early Retired Assets

This regulatory asset is related to the remaining net book

value of Big Bend Power Station Units 1

through 3 and smart meter assets that were retired. The

balance earns a rate of return as permitted by

the FPSC and will be recovered as a separate line item on customer

bills for a period of

15 years

. This

recovery mechanism is authorized by and survives the

term of the settlement agreement approved by the

FPSC in 2021. See “Tampa

Electric Big Bend Modernization Project” below for further

information.

Pension and Post-Retirement Medical Plan

This asset is primarily related to the deferred costs of pension

and post-retirement benefits at Tam

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

earns a rate of return as permitted by the FPSC

and New Mexico Public Regulation Commission (“NMPRC”)

as applicable. It is amortized over the

remaining service life of plan participants.

Regulated Fuel Adjustment Mechanism

This regulated

asset is the difference between actual fuel costs

and amounts recovered from NSPI

customers through electricity rates in a given year,

and deferred to a fuel adjustment mechanism (“FAM”)

regulatory asset or liability and recovered from or returned

to customers in a subsequent year.

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

three-year fuel stability plan, differences

between

actual fuel costs and fuel revenues recovered from customers

for the years 2020 to 2022, will be

recovered or returned to customers after 2022. The Nova Scotia Utility

and Review Board’s (“UARB”)

decision to approve the fuel stability plan directed that

any annual non-fuel revenues above NSPI’s

approved range of ROE are to be applied to the FAM.

NMGC Winter Event Gas Cost Recovery

In February 2021, the State of New Mexico experienced

an extreme cold weather event that resulted in

an incremental $

108

million USD for gas costs above what it would normally

have paid during this period.

NMGC normally recovers gas supply and related costs

through a purchased gas adjustment clause. On

April 16, 2021, NMGC filed a Motion for Extraordinary Relief,

as permitted by the NMPRC rules, to extend

the terms of the repayment of the incremental gas costs

and to recover a carrying charge. On June 15,

2021, the NMPRC approved the recovery of $

108

million USD and related borrowing costs over a period

of 30 months beginning July 1, 2021.

Cost Recovery Clauses

These assets and liabilities are related to Tampa

Electric, PGS and NMGC clauses and riders. They

are

recovered or refunded through cost-recovery mechanisms

approved by the FPSC or NMPRC, as

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

period.

Storm Restoration Regulatory Asset

This asset represents storm restoration costs, primarily

incurred by GBPC. GBPC maintains insurance for

its generation facilities and, as with most utilities, its transmission

and distribution networks are not

covered by commercial insurance.

In January 2020, the Grand Bahama Port Authority (“GBPA”)

approved the recovery of $

million USD

of costs related to Hurricane Dorian in 2019, over a

five

-year period. The recovery was implemented

through rates on January 1, 2021.

Restoration costs

associated with Hurricane Matthew in 2016 are being

recovered through an approved

fuel charge. Additional details on the recovery are included

under the GBPC section below.

The balance

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

million USD.

Environmental Remediations

This asset is primarily related to PGS costs associated with environmental

remediation at Manufactured

Gas Plant sites.

The balance is included in rate base, partially offsetting

the related liability,

and earns a

rate of return as permitted by the FPSC. The timing of recovery

is based on a settlement agreement

approved by the FPSC.

Stranded Cost Recovery

Due to the decommissioning of a GBPC steam turbine

in 2012, the GBPA

approved the recovery of a $

million USD stranded cost through electricity rates; it is

included in rate base and is expected to be

included in rates in future years.

Deferrals Related to Derivative Instruments

This asset is primarily related to NSPI deferring changes in fair

value of derivatives that are documented

as economic hedges or that do not qualify for NPNS

exemption, as a regulatory asset or liability as

approved by its regulator. The

realized gain or loss is recognized when the hedged

item settles in

regulated fuel for generation and purchased power,

inventory, operating,

maintenance or general or

property, plant and equipment,

depending on the nature of the item being economically hedged.

DSM Deferral

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

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

The UARB directed EfficiencyOne, a franchisee

appointed by the Province of Nova Scotia to provide

NSPI with electricity efficiency and conservation

activities under the

Public Utilities Act

, to review

financing options through which EfficiencyOne

would borrow the 2015 deferral amount from

a commercial

lender in order to repay NSPI the amount it expended

on behalf of its customers in 2015. In December

2016, EfficiencyOne secured financing and $

million was advanced to NSPI to finance the 2015

DSM

deferral. In February 2017, EfficiencyOne advanced

an additional $

million to NSPI. As NSPI collects the

associated amounts from customers over the remaining

three years

, it will repay the balance to

EfficiencyOne. This has been set up as a liability in

“Other long-term liabilities” with the current portion

the liability included in “Other current liabilities” on the

Consolidated Balance Sheets.

Unamortized Defeasance Costs

Upon privatization in 1992, NSPI became responsible for

managing a portfolio of defeasance securities

held in trust that provide the principal and interest streams

to match the related defeased debt, which as

at December 31, 2021, totalled $

200

million (2020 – $

582

million). The excess of the cost of defeasance

investments over the face value of the related debt is deferred

on the balance sheet and amortized over

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

Accumulated Reserve – Cost of Removal (“COR”)

This regulatory liability represents the non-ARO COR reserve

in Tampa

Electric, PGS, NMGC and NSPI.

AROs represent the fair value of estimated cash flows

associated with the Company’s legal obligation

retire its property,

plant and equipment. Non-ARO COR represent estimated

funds received from

customers through depreciation rates to cover future

COR of property, plant

and equipment value upon

retirement that are not legally required. This reduces rate

base for ratemaking purposes. This liability is

reduced as COR are incurred and increased as depreciation

is recorded for existing assets and as new

assets are put into service.

Storm Reserve

The storm reserve is for hurricanes and other named storms

that cause significant damage to Tampa

Electric and PGS systems. As allowed by the FPSC, if

the charges to the storm reserve exceed the storm

liability, the excess

is to be carried as a regulatory asset. Tampa

Electric and PGS can petition the FPSC

to seek recovery of restoration costs over a 12-month

period, or longer, as determined

by the FPSC, as

well as replenish the reserve. In 2021, 2020 and 2019,

Tampa

Electric incurred storm restoration

preparation costs for multiple hurricanes of approximately $

million USD, which was charged to the

storm reserve regulatory liability

Regulatory Environments

Florida Electric Utility

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

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

Electric to collect total revenues or revenue requirements equal to their cost of providing service, plus an

appropriate return on invested capital.

Tampa

Electric’s approved regulated return on equity

(“ROE”) range for 2021 and 2020 was

9.25

per cent

11.25

per cent based on an allowed equity capital structure

per cent. An ROE of

10.25

per cent is

used for the calculation of the return on investments for

clauses.

Beginning in 2022, Tampa

Electric’s

approved regulated ROE range is

9.00

per cent to

11.00

per cent, based on an allowed equity capital

structure of

per cent. An ROE of

9.95

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

investments for clauses. See below for further detail.

Fuel Recovery

Tampa

Electric has a fuel recovery clause approved by

the FPSC, allowing the opportunity to recover

fluctuating fuel expenses from customers through annual fuel

rate adjustments. The FPSC annually

approves cost-recovery rates for purchased power,

capacity, environmental

and conservation costs,

including a return on capital invested. Differences

between the prudently incurred fuel costs and the

cost-

recovery rates and amounts recovered from customers

through electricity rates in a year are deferred to a

regulatory asset or liability and recovered from or returned

to customers in a subsequent year.

On January 19, 2022, Tampa

Electric requested a mid-course adjustment to its fuel

and capacity charges

to recover an additional $

169

million USD, effective with April 2022 customer

bills, due to an increase in

fuel commodity and capacity costs. The FPSC is expected

to issue its decision in March 2022.

On July 19, 2021, Tampa

Electric requested a mid-course adjustment of $

million USD to its fuel and

capacity charges, effective with September 2021

customer bills, due to an increase in fuel commodity

and

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

approved the request to recover the costs during

the months of September through December 2021.

Base rates

On August 6, 2021, Tampa

Electric filed with the FPSC a joint motion for approval of

a settlement

agreement (the “Settlement Agreement”) by Tampa

Electric and the intervenors in relation to its rate case

filed with the FPSC in April 2021. The Settlement Agreement

provides for a projected increase of $

191

million USD in rates annually,

effective with January 2022 bills. This increase

will consist of $

123

million

USD in base rate charges and $

million USD to recover the costs of retiring assets

including, Big Bend

coal generation assets Units 1 through 3 and meter assets.

The Settlement Agreement further includes

two subsequent year adjustments of $

million USD and $

million USD, effective January 2023 and

January 2024, respectively related to the recovery of future

investments in the Big Bend Modernization

project and solar generation. The allowed equity in the

capital structure will continue to be

per cent

from investor sources of capital. The Settlement Agreement

includes an allowed regulated ROE range of

9.0

per cent to

11.0

per cent with a

9.95

per cent midpoint. It also provides for a

basis point increase in

the allowed ROE range and mid-point, and $

million USD of additional revenue, if U.S. Treasury

Bond

yields exceed a specific threshold set on the date the

FPSC votes to approve the agreement. Under the

agreement, base rates will not further change from January

1, 2022 through December 31, 2024, unless

Tampa

Electric’s earned ROE were to fall below the

bottom of the range during that time. The Settlement

Agreement contains a provision whereby Tampa

Electric agrees to quantify the future impact

of a change

in tax rates on net operating income through a reduction

or increase in base revenues within 180 days of

when such tax change becomes law or its effective

date. The Settlement Agreement further creates a

mechanism to recover the costs of retiring coal generation

units and meter assets over a period of 15

years which survives the term of that agreement. The

Settlement Agreement sets new depreciation and

dismantlement rates effective January 1, 2022 and

contains the provisions that Tampa

Electric will not

have to file another depreciation study during the term

of the agreement but will file a new depreciation

study no more than one year,

nor less than 90 days, before the filing of its next general

base rate

proceeding. Tampa

Electric agreed not to hedge natural gas through the period

ending on December 31,

On October 21, 2021, the FPSC approved the Settlement

Agreement and the final order,

reflecting

such approval, was issued in November 2021.

On April 9, 2019, Tampa

Electric reached a settlement agreement with consumer

parties regarding

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

which was approved by the FPSC on May 21,

As a result, Tampa

Electric refunded $

million USD to customers in January 2020, resulting in

minimal impact to the Consolidated Statements of Income.

Solar Base Rate Adjustments Included in Base Rates

As of December 31, 2021, Tampa

Electric has invested $

850

million USD in

600

MW of utility-scale solar

photovoltaic projects, which are recoverable through FPSC-approved

solar base rate adjustments

(“SoBRAs”). AFUDC is being earned on these projects

during construction. The FPSC has approved

SoBRAs representing a total of

600

MW or $

104

million USD annually in estimated revenue requirements

for in-service projects.

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

requirement estimates that were included in base

rates as of September 2018 and January 2019, respectively,

was submitted on April 30, 2020, and the

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

million USD true-up was returned to customers in

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

for SoBRA tranche 3, included in base

rates as of January 2020. An estimated $

million true-up was returned to customers during

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

Storm Protection Cost Recovery Clause and Settlement

Agreement

On October 3, 2019, the FPSC issued a rule to implement

a Storm Protection Plan (“SPP”) Cost

Recovery Clause. This clause provides a process for Florida

investor-owned utilities, including Tampa

Electric, to recover transmission and distribution storm hardening

costs for incremental activities not

already included in base rates. Tampa

Electric submitted its storm protection plan with

the FPSC on April

10, 2020. On April 27, 2020, Tampa

Electric submitted a settlement agreement with

the FPSC which

specified a $

million USD base rate reduction for SPP program costs

previously recovered in base

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

FPSC approved this settlement agreement. On

August 3, 2020, Tampa

Electric submitted another settlement agreement to the

FPSC for approval,

including cost recovery of approximately $

million USD in proposed storm protection project costs

for

2020 and 2021. This cost recovery includes the $

million USD of costs removed from base rates. This

settlement agreement was approved on August 10,

2020 and Tampa

Electric’s cost recovery began in

January 2021. The current approved plan will apply for

the years 2020, 2021 and 2022, and

Tampa

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

recovery in 2023, 2024, and 2025.

The June 9, 2020 settlement agreement approved by the

FPSC disclosed above also included approval

of Tampa

Electric’s petition to eliminate its $

million USD accumulated amortization reserve surplus

for

intangible software assets through a credit to amortization

expense in 2020.

Big Bend Modernization Project

Tampa

Electric expects to invest approximately $

850

million USD during 2018 through 2023 to modernize

the Big Bend Power Station,

of which approximately $

695

million USD has been invested through

December 31, 2021. The modernization project will repower

Big Bend Unit 1 with natural gas combined-

cycle technology and eliminate coal as this unit’s

fuel. As part of the modernization project, Tampa

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

the modernized plant in 2020 and Big Bend

Unit 2 in 2021. Tampa

Electric plans to retire Big Bend Unit 3 in 2023 as it

is in the best interest of the

customers from an economic, environmental risk and operationa

perspectives.

At December 31, 2021, the balance sheet included $

636

million USD in electric utility plant and $

267

million USD in accumulated depreciation

related to Unit 1 components and Unit 2 and Unit

3 assets. In

accordance with Tampa

Electric’s 2017 settlement agreement approved

by the FPSC, Tampa

Electric

continued to account for its existing investment in Unit 1, 2

and 3 in electric utility plant and depreciate the

assets using the current depreciation rates until December

31, 2021, at which point they were reclassified

to a regulatory asset on the balance sheet.

Tampa

Electric’s Settlement Agreement provides recovery

for the Big Bend Modernization project in two

phases. The first phase is a revenue increase to cover the costs

of the assets in service during 2022,

among other items. The remainder of the project costs

will be recovered as part of the 2023 subsequent

year adjustment. The Settlement Agreement also includes

a new charge to recover the remaining costs of

the retiring Big Bend coal generation assets, Units 1

through 3, which will be spread over

15 years

and

will survive the termination of the Settlement Agreement. The

special capital recovery schedule for all

three units was applied beginning January 1, 2022.

Canadian Electric Utilities

NSPI

NSPI is a public utility as defined in the

Public Utilities Act of Nova Scotia

(“Public Utilities Act”) and is

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

The Public Utilities Act gives the UARB

supervisory powers over NSPI’s operations and

expenditures. Electricity rates for NSPI’s customers

are

also subject to UARB approval.

NSPI is regulated under a cost-of-service model, with rates

set to recover prudently incurred costs of

providing electricity service to customers and provide a

reasonable return to investors. NSPI’s approved

regulated ROE range for 2021 and 2020 was

8.75

per cent to

9.25

per cent based on an actual five

quarter average regulated common equity component

of up to

per cent.

NSPI has a FAM, approved

by UARB which enables it to seek recovery of its fuel

costs from customers

through regularly scheduled fuel rate adjustments. Differences

between actual fuel costs and amounts

recovered from customers through electricity rates in a

year are deferred to a FAM

regulatory asset or

liability and recovered from or returned to customers

in subsequent years.

NSPI is currently operating under a

three

-year fuel stability plan which results in an average annual

overall rate increase of

1.5

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

These rates

include recovery of Maritime Link costs.

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

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

a rate stability plan for 2022 through 2024 which includes average

base rate increases of

2.9

per cent per

year and average fuel rate increases pursuant to the FAM

0.8

per cent per year on August 1, 2022,

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

would result in annualized incremental

revenue (base and fuel rates) increases of $

million in 2022 ($

million related to August 1, 2022

through December 31, 2022), $

million in 2023 and $

million in 2024. A decision by the UARB is

expected later this year.

The Maritime Link is a $

1.8

billion (including AFUDC) transmission project including two

170-kilometre

sub-sea cables, connecting the island of Newfoundland and

Nova Scotia. The Maritime Link entered

service on January 15, 2018 and NSPI started interim

assessment payments to NSPML at that time. The

UARB approved 2021 interim cost assessment recovery

payment to NSPML was $

172

million (2020 -

145

million) and as of December 31, 2021 $

139

million (2020 - $

135

million) has been paid.

The

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

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

. For 2021, NSPI has

recorded a $

million (2020 - $

million) holdback payable to NSPML and NSPML has deferred

collection of $

million in depreciation expense in 2021. On January 18,

2022, the UARB directed NSPI

to pay to NSPML

approximately $

million of the 2021 holdback.

As part of a

three

-year fuel stability plan, electricity rates have been

set to include the $

145

million

approved Maritime Link assessment for 2020 and amounts

of $

164

million and $

162

million for 2021 and

2022, respectively.

Any difference between the amounts included

in the fuel stability plan and those

approved by the UARB through the NSPML interim assessment

application will be addressed through the

FAM.

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

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

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

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

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

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

subsequent to 2022.

NSPML

Equity earnings from the Maritime Link are dependent

on the approved ROE and operational

performance of NSPML. NSPML’s

approved regulated ROE range is

8.75

per cent to

9.25

per cent,

based on an actual five-quarter average regulated common

equity component of up to

per cent.

Nalcor’s NS Block delivery obligations commenced on August 15,

2021 and delivery will continue over the

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

NSPML filed a final capital cost

application with the UARB seeking approval to recover

capital costs associated with the Maritime Link

and approval of NSPML’s

2022 assessment. In December 2021, NSPML obtained

an interim decision

from the UARB approving interim rates beginning January

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

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

its decision relating to the Maritime Link

Project, approving NSPML’s

requested rate base of approximately $

1.8

billion less costs that would not

otherwise have been recoverable if incurred by NSPI.

The UARB also approved approximately $

168

million of NSPML revenue requirement in 2022 subject

to a holdback of $

million per month beginning

April 1, 2022 and thereafter

to the end of the year. This

holdback is to be used to fund any replacement

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

greater shortfall in contracted NS Block deliveries

each month and will otherwise be released to NSPML.

NSPML is required to provide the UARB with a

compliance filing by February 16, 2022 which will confirm the

impacts of this decision including the

amount of the unrecoverable items which are not expected

to exceed $

million (pre-tax).

Other Electric Utilities

The Barbados Light & Power Company Limited

BLPC is regulated by the Fair Trading

Commission (“FTC”),

an independent regulator, under

the Utilities

Regulation (Procedural) Rules 2003. The Government

of Barbados has granted BLPC a franchise to

generate, transmit and distribute electricity on the island

until 2028. In 2019, the Government of Barbados

passed legislation amending the number of licenses required

for the supply of electricity from a single

integrated license which currently exists to multiple licenses

for Generation, Transmission and

Distribution, Storage, Dispatch and Sales. In March 2021,

BLPC reached commercial agreement with the

Government of Barbados for each of the license types,

subject to the passage of implementing

legislation. Following a general election called late in 2021

for January 19, 2022, the new licenses are

expected to take effect in 2022 on completion

of the legislative process. The Dispatch license will have

term of

5 years

with the remaining licenses having terms ranging from

30 years

. BLPC anticipates that

any increased costs associated with the implementation

of the new multi-licensed structure will be

recoverable through BLPC’s regulatory framework.

BLPC is currently assessing the full impact of the

new

licenses on its business and working towards the successful

implementation of the licenses.

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

rates set to recover prudently incurred costs of

providing electricity service to customers and provide an

appropriate return to investors. BLPC’s

approved regulated return on rate base was

per cent for 2021 and 2020.

BLPC has a fuel pass-through mechanism which provides

the opportunity to recover all prudently

incurred fuel costs from customers in a timely manner.

The approved calculation of the fuel charge is

adjusted monthly and reported to the regulator.

On October 4, 2021 BLPC submitted a general rate review

application to the FTC. The application seeks

a rate adjustment and the implementation of a cost reflective

rate structure that will facilitate the changes

expected in the newly reformed electricity market and the

country’s transition towards 100 per cent

renewable energy generation. The application seeks

recovery of capital investment in plant, equipment

and related infrastructure and results in an increase in

annual non-fuel revenue of approximately $

million USD upon approval. The application includes a

request for allowed regulatory ROE of

12.50

per

cent on an allowed equity capital structure of

per cent. A decision is expected from the FTC in the

second half of 2022.

On October 21, 2021 the FTC approved BLPC’s application

to implement a fuel hedging program which

will be incorporated into the calculation of the fuel clause

adjustment. On November 10, 2021 BLPC

requested the FTC review the required

/50 cost sharing arrangement between BLPC and customers

relation to the hedging administrative costs, or any gains

and losses associated with the hedging

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

half of 2022.

In December 2018, the Government of Barbados signed the

Income Tax

Amendment Act

into law. This

legislation, which was effective January 1, 2019,

created a new corporate income tax rate schedule and

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

was required to remeasure its deferred

income tax liability at the new lower corporate income tax

rate, resulting in recognition of an income tax

recovery of $

million USD of which $

million USD was deferred as a regulatory

liability, all of which

was recognized in earnings in Q1 2020.

Grand Bahama Power Company Limited

GBPC is regulated by the GBPA.

The GBPA

has granted GBPC a licensed, regulated and exclusive

franchise to produce, transmit and distribute electricity

on the island until 2054. There is a fuel pass-

through mechanism and tariff review policy

with new rates submitted every three years. GBPC’s

approved

regulated return on rate base was

8.37

per cent for 2021 (2020 -

8.34

per cent).

On January 14, 2022, the GBPA

issued its decision on GBPC’s application

for rate review that was filed

with the GBPA on

September 23, 2021. The decision, which becomes

effective April 1, 2022, allows for

an increase in revenues of $

3.5

million USD. The new rates include a regulatory ROE

12.84

per cent.

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

result of Hurricane Matthew,

the GBPA approved

fixed per kWh fuel charge and allowed the difference

between this and the actual cost of fuel to be

applied to the Hurricane Matthew regulatory asset. In

September 2021, GBPC filed an application for rate

review with the GBPA.

As part of its decision issued January 14, 2022

and effective April 1, 2022, the

GBPA approved

the continued amortization of the remaining regulatory

asset over the three year period

ending December 31, 2024.

Dominica Electricity Services Ltd

Domlec is regulated by the Independent Regulatory Commission,

Dominica. On October 7, 2013, the

Independent Regulatory Commission, Dominica issued

a Transmission, Distribution & Supply

License

and a Generation License, both of which came into effect

on January 1, 2014, for a period of

years. Domlec’s approved allowable regulated return

on rate base was

per cent for 2021 and 2020.

Domlec has a fuel pass-through mechanism which provides

opportunity to recover substantially all

prudently incurred fuel costs in a timely manner.

Gas Utilities and Infrastructure

PGS

PGS is regulated by the FPSC. The FPSC sets rates at

a level that allows utilities such as PGS to collect

total revenues or revenue requirements equal to their

cost of providing service, plus an appropriate return

on invested capital.

PGS’s approved ROE range for 2021 was

8.9

per cent to

11.0

per cent with a

9.9

per cent midpoint,

based on an allowed equity capital structure of

54.7

per cent. PGS’s approved ROE range for

2020 was

9.25

per cent to

11.75

per cent, based on an allowed equity capital structure

54.7

per cent. An ROE of

10.75

per cent was used for the calculation of return on

investments for clauses.

PGS recovers the costs it pays for gas supply and

interstate transportation for system supply through its

purchased gas adjustment clause. This clause is designed to

recover actual costs incurred by PGS for

purchased gas, gas storage services, interstate pipeline capacity,

and other related items associated with

the purchase, distribution, and sale of natural gas to its

customers. These charges may be adjusted

monthly based on a cap approved annually by the FPSC.

The FPSC annually approves cost-recovery rates

for conservation costs and Cast Iron/Bare Steel Pipe

Replacement costs, including a return on capital invested

incurred in developing and implementing

energy conservation programs. The Cast Iron/Bare Steel

Pipe Replacement clause is to recover the cost

of accelerating the replacement of cast iron and bare

steel distribution lines in the PGS system. The

FPSC approved a replacement program of approximately

per cent, or

800

kilometres, of the PGS

system at a cost of approximately $

million USD over a

-year period beginning in 2013.

In February

2017, the FPSC approved an amendment to the cast iron

bare steel rider to include certain plastic

materials and pipe deemed obsolete by Pipeline and Hazardous

Materials Safety Administration, totaling

approximately

880

kilometres. PGS estimates that the majority of cast

iron and bare steel pipe will be

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

of obsolete plastic pipe continuing until

2028 under the rider.

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

The settlement

agreement allows for an increase to base rates by $

million USD annually effective January 1 2021,

which is a $

million USD increase in revenue and $

million USD increase of revenues previously

recovered through the cast iron and bare steel replacement

rider. It provides

PGS the ability to reverse a

total of $

million USD of accumulated depreciation through

PGS has not reversed any of this

accumulated depreciation to date. In addition, the agreement

sets new depreciation rates effective

January 1, 2021. Under the agreement base rates are

frozen from January 1, 2021 to December 31,

2023, unless its earned ROE were to fall below

8.9

per cent before that time with an allowed equity in the

capital structure of

54.7

per cent from investor sources of capital. The settlement

agreement provides for

the deferral of income taxes as a result of changes in

tax laws. The changes would be reflected as

regulatory asset or liability and either result in an increase

or a decrease in customer rates through a

subsequent regulatory process.

NMGC

NMGC is subject to regulation by the NMPRC. The NMPRC

sets rates at a level that allows NMGC to

collect total revenues equal to its cost of providing

service, plus an appropriate return on invested

capital.

NMGC’s approved ROE for 2021 was

9.375

per cent on an allowed equity capital structure of

per cent.

The approved ROE for 2020 was

9.10

per cent on an allowed capital structure of

per cent.

NMGC recovers gas supply costs through a purchased

gas adjustment clause (“PGAC”). This clause

recovers NMGC’s actual costs for purchased gas, gas

storage services, interstate pipeline capacity,

and

other related items associated with the purchase, transmi

ssion, distribution, and sale of natural gas to its

customers. On a monthly basis, NMGC can adjust the

charges based on the next month’s expected cost

of gas and any prior month under-recovery or over-recovery.

The NMPRC requires that NMGC annually

file a reconciliation of the PGAC period costs and recoveries.

NMGC must file a PGAC Continuation Filing

with the NMPRC every four years to establish that the

continued use of the PGAC is reasonable and

necessary. In December

2020, NMGC received approval of its PGAC Continuation

Filing for the four-year

period ending December 2024.

In February 2021, the State of New Mexico experienced

an extreme cold weather event that resulted in

an incremental $

108

million USD for gas costs above what it would normally

have paid during this period.

On June 15, 2021, the NMPRC approved the recovery

over a period of

months beginning July 1,

For more information, refer to the “NMGC Winter

Event Gas Cost Recovery” section above.

On December 16, 2020, the NMPRC approved a settlement

agreement for new rates that became

effective on January 1, 2021. The new rates reflect

the recovery of capital investment in pipelines and

related infrastructure and resulted in an increase in revenue

of approximately $

million USD annually.

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

the NMPRC for new rates to become effective

January 2023. NMGC requested a $

million increase in annual base revenues primarily

as a result of

increased operating costs and capital investments in pipelines

and related infrastructure. A decision from

the NMPRC is expected by the end of 2022.

Brunswick Pipeline

Brunswick Pipeline is a

145

-kilometre pipeline delivering natural gas from the Canaport™

LNG import

terminal near Saint John, New Brunswick to markets in

the northeastern United States. Brunswick

Pipeline entered into a

-year firm service agreement commencing in July

2009 with Repsol Energy

Canada. The agreement provides for a predetermined

toll increase in the fifth and fifteenth year of the

contract. The pipeline is considered

a Group II pipeline regulated by the Canada Energy Regulator

(“CER”). The CER Gas Transportation Tariff

is filed by Brunswick Pipeline in compliance with the

requirements of the

CER Act

and sets forth the terms and conditions of the transportation

rendered by

Brunswick Pipeline.

INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME

Equity Income

Percentage

Carrying Value

For the year ended

As at December 31

December 31

Ownership

millions of Canadian dollars

2021

2020

2021

2020

2021

LIL

(1)

682

629

37.4

NSPML

533

547

100.0

M&NP

(2)

123

129

12.9

Lucelec

(2)

19.5

Bear Swamp

(3)

50.0

1,382

1,346

143

149

(1) Emera indirectly owns

100

per cent of the Class B units, which comprises

24.9

per cent of the total units issued. Percentage

ownership in LIL is subject to change, based on

the balance of capital investments required

from Emera and Nalcor Energy to

complete construction of the LIL. Emera’s ultimate percentage

investment in LIL will be determined upon

final costing of

all transmission projects related to the Muskrat

Falls development, including the LIL, Labrador

Transmission Assets and Maritime

Link Projects, such that Emera’s total investment in the Maritime

Link and LIL will equal

per cent of the cost of all of these

transmission developments.

(2) Although Emera’s ownership percentage of these entities

is relatively low, it is considered to have significant influence over the

operating and financial decisions of these companies

through Board representation. Therefore, Emera

records its investment in

these entities using the equity method.

(3) The investment balance in Bear Swamp is

in a credit position primarily as a result

of a $

179

million distribution received in 2015.

Bear Swamp's credit investment balance of $

104

million (2020 – $

118

million) is recorded in Other long-term liabilities

on the

Consolidated Balance Sheets.

Equity investments include a $

million difference between the cost and the

underlying fair value of the

investees' assets as at the date of acquisition. The excess

is attributable to goodwill.

Emera accounts for its variable interest investment in

NSPML as an equity investment (note 32).

NSPML's consolidated summarized balance sheets are illustrated

as follows:

As at

December 31

millions of Canadian dollars

2021

2020

Balance Sheets

Current assets

Property, plant and equipment

1,587

1,629

Regulatory assets

247

210

Non-current assets

Total

assets

1,890

1,928

Current liabilities

Long-term debt

(1)

1,189

1,228

Non-current liabilities

118

Equity

533

547

Total

liabilities and equity

1,890

1,928

(1) The project debt has been guaranteed

by the Government of Canada.

OTHER INCOME, NET

Other income, net consisted of the following:

For the

Year ended December 31

millions of Canadian dollars

2021

2020

Allowance for equity funds used during construction

Gain on sale of Emera Maine, net of transaction costs

(1)

585

TECO Guatemala Holdings award

(2)

Other

708

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

the gain on sale of Emera Maine.

(2) Refer to note 27 for further detail related

to the TECO Guatemala Holdings award.

10.

INCOME TAXES

The income tax provision, for the years ended December

31, differs from that computed using the

enacted combined Canadian federal and provincial statutory

income tax rate for the following reasons:

millions of Canadian dollars

2021

2020

Income before provision for income taxes

555

1,325

Statutory income tax rate

29.0%

29.5%

Income taxes, at statutory income tax rate

161

391

Additional impact from the sale of Emera Maine

102

Deferred income taxes on regulated income recorded as regulatory assets and

regulatory liabilities

(62)

(48)

Foreign tax rate variance

(42)

(45)

Amortization of deferred income tax regulatory liabilities

(33)

(44)

Tax

effect of equity earnings

(16)

(15)

Tax

credits

(13)

(12)

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

Other

(1)

Income tax (recovery) expense

(6)

341

Effective income tax rate

(1%)

26%

The change in the effective income tax rate was

primarily due to decreased income before provision

for

income taxes and the additional impact from the sale

of Emera Maine in 2020.

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

Measures (2020) Act was enacted, which

included a reduction in the Nova Scotia provincial corporate

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

combined Canadian federal and provincial statutory income tax

rate was reduced from

per cent to

29.5

per cent for 2020, and further reduced to

per cent for 2021 onward.

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

recorded a reduction of $

million to its net

deferred income tax liabilities and an offsetting

reduction to its net deferred income tax regulatory

asset,

as the benefit of lower net deferred income tax liabilities

is expected to be returned to customers in future

years. The Company also recognized a $

million income tax expense as a result of the revaluation

certain net deferred income tax assets.

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

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

CARES Act”) was signed into law.

Under the CARES Act, companies can accelerate

the refund of

alternative minimum tax (“AMT”) credit carryforwards.

As a result, the Company received the balance of

its $

145

million of refundable AMT credit carryforwards

in 2020. The Company has not had any other

material impacts from the CARES Act.

The following table reflects the composition of taxes on

income from continuing operations presented in

the Consolidated Statements of Income for the years ended

December 31:

millions of Canadian dollars

2021

2020

Current income taxes

Canada

United States

(58)

Deferred income taxes

Canada

(33)

United States

118

426

Other

(9)

Investment tax credits

United States

(11)

(10)

Operating loss carryforwards

Canada

(64)

(46)

United States

(49)

Income tax (recovery) expense

(6)

341

The following table reflects the composition of income

before provision for income taxes presented in the

Consolidated Statements of Income for the years ended

December 31:

millions of Canadian dollars

2021

2020

Canada

244

176

United States

289

1,142

Other

Income before provision for income taxes

555

1,325

The deferred income tax assets and liabilities presented in

the Consolidated Balance Sheets as at

December 31 consisted of the following:

millions of Canadian dollars

2021

2020

Deferred income tax assets:

Tax

loss carryforwards

873

724

Tax

credit carryforwards

375

319

Derivative instruments

188

108

Regulatory liabilities - cost of removal

170

184

Other

434

375

Total

deferred income tax assets before valuation allowance

2,040

1,710

Valuation allowance

(256)

(202)

Total

deferred income tax assets after valuation allowance

1,784

1,508

Deferred income tax (liabilities):

Property, plant and equipment

(2,622)

(2,450)

Derivative instruments

(197)

(93)

Other

(538)

(385)

Total

deferred income tax liabilities

(3,357)

(2,928)

Consolidated Balance Sheets presentation:

Long-term deferred income tax assets

295

209

Long-term deferred income tax liabilities

(1,868)

(1,629)

Net deferred income tax liabilities

(1,573)

(1,420)

Considering all evidence regarding the utilization of the Company’s

deferred income tax assets, it has

been determined that Emera is more likely than not to realize

all recorded deferred income tax assets,

except for certain loss carryforwards and unrealized capital

losses on investments. A valuation allowance

of $

256

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

202

million) related to the loss

carryforwards and investments.

The Company intends to indefinitely reinvest earnings

from certain foreign operations. Accordingly,

2.9

billion as at December 31, 2021 (2020 - $

2.7

billion) in cumulative temporary differences

for which

deferred taxes might otherwise be required, have not

been recognized. It is impractical to estimate the

amount of income and withholding tax that might be payable

if a reversal of temporary differences

occurred.

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

and tax credit carryforwards and their expiration periods

as at December 31, 2021 consisted of the following:

Subject to

Tax

Valuation

Net Tax

Expiration

millions of Canadian dollars

Carryforwards

Allowance

Carryforwards

Period

Canada

NOL

1,776

(791)

985

2026 - 2041

Capital loss

(75)

Indefinite

United States

Federal NOL

1,521

2032 - Indefinite

State NOL

817

2032 - Indefinite

Tax credit

375

2025 - 2041

Other

NOL

(38)

2022 - 2028

The following table provides details of the change in unrecognized

tax benefits for the years ended

December 31 as follows:

millions of Canadian dollars

2021

2020

Balance, January 1

Increases due to tax positions related to current year

Increases due to tax positions related to a prior year

Decreases due to tax positions related to a prior year

(1)

(2)

Decreases due to settlement with tax authorities

(6)

Balance, December 31

The total amount of unrecognized tax benefits as at December

31, 2021 was $

million (2020 - $

million), which would affect the effective

tax rate if recognized. The total amount of accrued interest

with

respect to unrecognized tax benefits was $

million (2020 - $

million) with nil interest expense

recognized in the Consolidated Statements of Income

(2020 - $

million).

penalties have been

accrued. The balance of unrecognized tax benefits could

change in the next 12 months as a result of

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

Service audits. A reasonable estimate

of any change cannot be made at this time.

NSPI and the CRA are currently in a dispute with respect

to the timing of certain tax deductions for

NSPI’s 2006 through 2010 taxation years. The ultimate

permissibility of the tax deductions is not in

dispute; rather, it is the timing

of those deductions. The cumulative net amount in

dispute to date is $

million, including interest. NSPI has prepaid $

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

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

with the Tax

Court of Canada with respect to its

dispute. Should NSPI be successful in defending its position,

all payments including applicable interest

will be refunded. If NSPI is unsuccessful in defending

any portion of its position, the resulting taxes and

applicable interest will be deducted from amounts previously

paid, with the excess, if any,

owing to CRA.

The related tax deductions will be available in subsequent years.

Should NSPI be similarly reassessed by the CRA for years

not currently in dispute, further payments will

be required; however, the

ultimate permissibility of these deductions would be

similarly not in dispute.

NSPI and its advisors believe that NSPI has reported

its tax position appropriately.

NSPI continues to

assess its options to resolving the dispute; however,

the outcome of the Appeal process is not

determinable at this time.

Emera files a Canadian federal income tax return, which includes

its Nova Scotia and New Brunswick

provincial income tax. Emera’s subsidiaries file

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

tax returns. As at December 31, 2021, the Company’s

tax years still open to examination by taxing

authorities include 2005 and subsequent years.

11.

COMMON STOCK

Authorized

Unlimited number of non-par value common shares.

2021

2020

Issued and outstanding:

millions

of shares

millions of

Canadian

dollars

millions of

Canadian

dollars

Balance, December 31, 2020

251.43

6,705

242.48

6,216

Issuance of common stock

(1)(2)

4.99

284

4.54

251

Issued under Purchase Plans at market rate

4.32

239

3.99

219

Discount on shares purchased under Dividend Reinvestment Plan

(4)

Options exercised under senior management share option plan

0.33

0.42

Employee Share Purchase Plan

Balance, December 31, 2021

261.07

7,242

251.43

6,705

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

4,544,025

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

program "(ATM program)"

at an average price of $

56.04

per share for gross proceeds of $

255

million ($

251

million net of issuance costs).

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

4,987,123

common shares were issued under Emera's ATM program at an average

price

of $

57.63

per share for gross proceeds of $

287

million ($

284

million net of after-tax issuance costs).

On August 12, 2021, Emera renewed its ATM

Program that allows the Company to issue up to $

600

million of common shares from treasury to the public from

time to time, at the Company's discretion, at

the prevailing market price. The ATM

Program was renewed pursuant to a prospectus supplement

to the

Company's short form base shelf prospectus dated August

5, 2021. The ATM

program is expected to

remain in effect until September 5, 2023. As at

December 31, 2021, an aggregate gross sales limit of

457

million remains available for issuance under the ATM

program.

As at December 31, 2021, the following common shares

were reserved for issuance:

6.2

million (2020 –

3.5

million) under the senior management stock option

plan,

3.1

million (2020 –

3.5

million) under the

employee common share purchase plan and

14.2

million (2020 –

5.1

million) under the dividend

reinvestment plan (“DRIP”).

The issuance of common shares under the common share compensation

arrangements does not allow

the plans to exceed

per cent of Emera's outstanding common shares. As at

December 31, 2021,

Emera is in compliance with this requirement.

12.

EARNINGS PER SHARE

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

net income attributable to common

shareholders by the weighted average number of common shares

and DSUs outstanding during the

period. Diluted EPS is computed by dividing net income

attributable to common shareholders by the

weighted average number of common shares and DSUs

outstanding during the period, adjusted for the

exercise and/or conversion of all potentially dilutive securities.

Such dilutive items include Company

contributions to the senior management stock option plan, convertible

debentures and shares issued

under the dividend reinvestment plan.

The following table reconciles the computation of basic

and diluted earnings per share:

For the

Year ended December 31

millions of Canadian dollars (except per share amounts)

2021

2020

Numerator

Net income attributable to common shareholders

510.5

937.6

Diluted numerator

510.5

937.6

Denominator

Weighted average shares of common stock outstanding

255.9

246.5

Weighted average deferred share units outstanding

1.3

Weighted average shares of common stock outstanding – basic

257.2

247.8

Stock-based compensation

0.4

Weighted average shares of common stock outstanding – diluted

257.6

248.2

Earnings per common share

Basic

1.98

3.78

Diluted

1.98

3.78

13.

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The components of accumulated other comprehensive income

are as follows:

millions of Canadian dollars

Unrealized

(loss) gain on

translation of

self-sustaining

foreign

operations

Net change in

net investment

hedges

(Losses)

gains on

derivatives

recognized as

cash flow

hedges

Net change

on available-

for-sale

investments

Net change in

unrecognized

pension and

post-retirement

benefit costs

Total

AOCI

For the year ended December 31, 2021

Balance, January 1, 2021

(1)

(161)

(79)

Other comprehensive

income (loss) before

reclassifications

(42)

(19)

Amounts reclassified from

accumulated other

comprehensive income

(loss)

(1)

124

123

Net current period other

comprehensive income

(loss)

(42)

124

104

Balance, December 31,

2021

(1)

(37)

For the year ended December 31, 2020

Balance, January 1, 2020

253

(1)

(160)

Other comprehensive

income (loss) before

reclassifications

(201)

(175)

Amounts reclassified from

accumulated other

comprehensive income

(loss)

(1)

Net current period other

comprehensive income

(loss)

(201)

(1)

(174)

Balance, December 31,

2020

(1)

(161)

(79)

The reclassifications out of accumulated other comprehensive

income (loss) are as follows:

For the

Year ended December 31

millions of Canadian dollars

2021

2020

Affected line item in the Consolidated Financial Statements

(Gains) Losses on derivatives recognized as cash flow hedges

Foreign exchange forwards

Operating revenue – regulated

Interest rate hedge

Interest expense, net

(1)

Total

(1)

Net change in unrecognized pension and post-retirement benefit costs

Actuarial losses (gains)

Other income, net

Past service costs (gains)

Other income, net

(1)

Amounts reclassified into obligations

Pension and post-retirement benefits

102

(16)

Total

before tax

126

(2)

Income tax (expense) recovery

(2)

Total

net of tax

124

(1)

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

123

14.

INVENTORY

As at

December 31

millions of Canadian dollars

2021

2020

Fuel

255

199

Materials

283

254

538

453

15.

DERIVATIVE

INSTRUMENTS

Derivative assets and liabilities relating to the foregoing categories

consisted of the following:

Derivative Assets

Derivative Liabilities

As at

December 31

millions of Canadian dollars

2021

2020

2021

2020

Cash flow hedges

Interest rate hedge

Regulatory deferral

Commodity swaps and forwards

Coal purchases

Power purchases

Natural gas purchases and sales

Heavy fuel oil purchases

Foreign exchange forwards

Physical natural gas purchases and sales

241

HFT derivatives

Power swaps and physical contracts

Natural gas swaps, futures, forwards, physical

contracts

208

139

818

346

241

152

850

359

Other derivatives

Equity derivatives

Foreign exchange forwards

Total

gross current derivatives

493

184

874

424

Impact of master netting agreements with intent to

settle net or simultaneously

(192)

(86)

(192)

(86)

Total derivatives

301

682

338

Current

195

533

251

Long-term

106

149

Total derivatives

301

682

338

Derivative assets and liabilities are classified as current

or long-term based upon the maturities of the

underlying contracts.

Details of master netting agreements, shown net on the Consolidated

Balance Sheets, are summarized in

the following table:

Derivative Assets

Derivative Liabilities

As at

December 31

millions of Canadian dollars

2021

2020

2021

2020

Regulatory deferral

HFT derivatives

188

Total

impact of master netting agreements with

intent to settle net or simultaneously

192

Cash Flow Hedges

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

of $

million USD that will be amortized

through interest expense over

10 years

. As of December 31, 2021, there were

outstanding cash flow

hedges.

The amounts related to cash flow hedges recorded in income

and AOCI consisted of the following:

For the

Year ended December 31

millions of Canadian dollars

2021

2020

Interest

Foreign

rate hedge

exchange forwards

Realized loss in operating revenue – regulated

(2)

Realized gain in interest expense, net

Total

gains (losses) in net income

(2)

As at

December 31

millions of Canadian dollars

2021

2020

Interest

rate hedge

Total

unrealized gain in AOCI – effective portion, net of tax

The Company expects $

million of unrealized gains currently in AOCI to be reclassified

into net income

within the next 12 months.

Regulatory Deferral

The Company has recorded the following changes in realized

and unrealized gains (losses) with respect

to derivatives receiving regulatory deferral:

For the

Year ended December 31

millions of Canadian dollars

2021

Natural gas

Commodity

swaps and

forwards

Foreign

exchange

forwards

Unrealized gain (loss) in regulatory assets

(7)

Unrealized gain (loss) in regulatory liabilities

218

(3)

Realized (gain) in regulatory liabilities

(3)

Realized (gain) loss in inventory

(1)

(8)

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

power

(2)

(39)

Total

change derivative instruments

161

(1) Realized (gains) losses will be recognized in

fuel for generation and purchased power when

the hedged item is consumed.

(2) Realized (gains) losses on derivative instruments

settled and consumed in the period and hedging relationships

that have been

terminated or the hedged transaction is no longer

probable.

For the

Year ended December 31

millions of Canadian dollars

2020

Natural gas

Commodity

swaps and

forwards

Foreign

exchange

forwards

Unrealized gain (loss) in regulatory assets

(36)

(11)

Unrealized gain (loss) in regulatory liabilities

Realized gain (loss) in regulatory assets

Realized (gain) loss in regulatory liabilities

Realized (gain) loss in inventory

(1)

(2)

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

power

(2)

(3)

Total

change derivative instruments

(13)

(1) Realized (gains) losses will be recognized in

fuel for generation and purchased power when

the hedged item is consumed.

(2) Realized (gains) losses on derivative instruments

settled and consumed in the period and hedging relationships

that have been

terminated or the hedged transaction is no longer

probable.

Commodity Swaps and Forwards

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

notional volumes of commodity swaps and

forward contracts designated for regulatory deferral that are

expected to settle as outlined below:

2022

2023-2024

millions

Purchases

Natural Gas (Mmbtu)

Power (MWh)

Foreign Exchange Swaps and Forwards

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

notional volumes of foreign exchange swaps

and forward contracts designated for regulated deferral that

are expected to settle as outlined below:

2022

2023-2024

Foreign exchange contracts (millions of US dollars)

170

150

Weighted average rate

1.3047

1.2413

% of USD requirements

65%

29%

The Company reassesses foreign exchange forecasted periodically

and will enter into additional hedges

or unwind existing hedges, as required.

Held-for-Trading Derivatives

In the ordinary course of its business, Emera enters into

physical contracts for the purchase and sale of

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

forwards and futures, to economically hedge those

physical contracts. These derivatives are all considered

HFT.

The Company has recognized the following realized and

unrealized gains (losses) with respect to HFT

derivatives:

For the

Year ended December 31

millions of Canadian dollars

2021

2020

Power swaps and physical contracts in non-regulated operating revenues

(1)

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

operating revenues

(142)

205

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

generation and purchased power

(4)

(138)

200

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

notional volumes of outstanding HFT

derivatives that are expected to settle as outlined below:

millions

2022

2023

2024

2025

2026

Natural gas purchases (Mmbtu)

308

Natural gas sales (Mmbtu)

335

103

Power purchases (MWh)

Power sales (MWh)

Other Derivatives

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

in place to manage the cash flow risk

associated with forecasted future cash settlements of deferred

compensation obligations and foreign

exchange forwards in place to manage cash flow risk

associated with forecasted USD cash inflows.

The

equity derivative hedges the return on

2.8

million shares and extends until December of 2022. The

foreign

exchange forwards have a combined notional amount

of $

million USD and expire throughout 2022 and

2023.

For the

Year ended December 31

millions of Canadian dollars

2021

2020

Foreign

Exchange

Equity

Exchange

Equity

Forwards

Derivatives

Forwards

Derivatives

Unrealized gain (loss) in operating, maintenance and general

(1)

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

(15)

Realized gain (loss) in operating, maintenance and general

(3)

Realized gain (loss) in other income (expense)

(2)

Total

gains (losses) in net income

(4)

Credit Risk

The Company is exposed to credit risk with respect to

amounts receivable from customers, energy

marketing collateral deposits and derivative assets. Credit risk

is the potential loss from a counterparty’s

non-performance under an agreement. The Company manages

credit risk with policies and procedures

for counterparty analysis, exposure measurement, and

exposure monitoring and mitigation. Credit

assessments are conducted on all new customers and

counterparties, and deposits or collateral are

requested on any high risk accounts.

The Company assesses the potential for credit losses

on a regular basis and, where appropriate,

maintains provisions. With respect to counterparties, the Company

has implemented procedures to

monitor the creditworthiness and credit exposure of counterparties

and to consider default probability in

valuing the counterparty positions. The Company monitors

counterparties’ credit standing, including those

that are experiencing financial problems, have significant swings

in default probability rates, have credit

rating changes by external rating agencies, or have changes

in ownership. Net liability positions are

adjusted based on the Company’s current default probability.

Net asset positions are adjusted based on

the counterparty’s current default probability.

The Company assesses credit risk internally for

counterparties that are not rated.

As at December 31, 2021, the maximum exposure the

Company has to credit risk is $

1.3

billion (2020 -

805

million), which includes accounts receivable net of collateral/deposits

and assets related to

derivatives.

It is possible that volatility in commodity prices could cause

the Company to have material credit risk

exposures with one or more counterparties. If such counterparties

fail to perform their obligations under

one or more agreements, the Company could suffer

a material financial loss. The Company transacts with

counterparties as part of its risk management strategy for managing

commodity price, foreign exchange

and interest rate risk. Counterparties that exceed established

credit limits can provide a cash deposit or

letter of credit to the Company for the value in excess

of the credit limit where contractually required. The

total cash deposits/collateral on hand as at December

31, 2021 was $

341

million (2020 - $

251

million),

which mitigates the Company’s maximum credit

risk exposure. The Company uses the cash as payment

for the amount receivable or returns the deposit/collateral to

the customer/counterparty where it is no

longer required by the Company.

The Company enters into commodity master arrangements

with its counterparties to manage certain

risks, including credit risk to these counterparties. The

Company generally enters into International Swaps

and Derivatives Association agreements (“ISDA”), North American

Energy Standards Board agreements

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

The Company believes that entering into such

agreements offers protection by creating contractual rights

relating to creditworthiness, collateral, non-

performance and

default.

As at December 31, 2021, the Company had $

114

million (2020 - $

123

million) in financial assets,

considered to be past due, which have been outstanding for

an average

days. The fair value of these

financial assets is $

million (2020 - $

101

million), the difference of which is included in

the allowance for

credit losses. These assets primarily relate to accounts

receivable from electric and gas revenue.

Concentration Risk

The Company's concentrations of risk consisted of the

following:

As at

December 31, 2021

December 31, 2020

millions of

Canadian

dollars

% of total

exposure

millions of

Canadian

dollars

% of total

exposure

Receivables, net

Regulated utilities

Residential

384

24%

341

32%

Commercial

167

10%

143

14%

Industrial

Other

696

43%

629

60%

Trading group

Credit rating of A- or above

Credit rating of BBB- to BBB+

107

Not rated

132

305

19%

170

16%

Other accounts receivable

329

20%

159

15%

1,330

82%

958

91%

Derivative Instruments

(current and long-term)

Credit rating of A- or above

155

Credit rating of BBB- to BBB+

Not rated

124

301

18%

1,631

100%

1,056

100%

Cash Collateral

The Company’s cash collateral positions consisted

of the following:

As at

December 31

millions of Canadian dollars

2021

2020

Cash collateral provided to others

212

Cash collateral received from others

100

Collateral is posted in the normal course of business based

on the Company’s creditworthiness, including

its senior unsecured credit rating as determined by certain

major credit rating agencies. Certain

derivatives contain financial assurance provisions that require

collateral to be posted if a material adverse

credit-related event occurs. If a material adverse event resulted

in the senior unsecured debt falling below

investment grade, the counterparties to such derivatives

could request ongoing full collateralization.

As at December 31, 2021, the total fair value of derivatives

in a liability position was $

682

million

(December 31, 2020

–

338

million). If the credit ratings of the Company were reduced

below investment

grade, the full value of the net liability position could be required

to be posted as collateral for these

derivatives.

16.

FAIR VALUE

MEASUREMENTS

The Company is required to determine the fair value of

all derivatives except those which qualify for the

NPNS exemption (see note 1) and uses a market approach

to do so. The three levels of the fair value

hierarchy are defined as follows:

Level 1 - Where possible, the Company bases the fair

valuation of its financial assets and liabilities on

quoted prices in active markets (“quoted prices”) for identical

assets and liabilities.

Level 2 - Where quoted prices for identical assets and liabilities

are not available, the valuation of certain

contracts must be based on quoted prices for similar assets

and liabilities with an adjustment related to

location differences. Also, certain derivatives are valued

using quotes from over-the-counter clearing

houses.

Level 3 - Where the information required for a Level 1

or Level 2 valuation is not available, derivatives

must be valued using unobservable or internally-developed

inputs. The primary reasons for a Level 3

classification are as follows:

●

While valuations were based on quoted prices, significant assumptions

were necessary to reflect

seasonal or monthly shaping and locational basis differentials.

●

The term of certain transactions extends beyond the period when

quoted prices are available, and

accordingly, assumptions

were made to extrapolate prices from the last quoted

period through the

end of the transaction term.

●

The valuations of certain transactions were based on internal

models, although quoted prices were

utilized in the valuations.

Derivative assets and liabilities are classified in their entirety based

on the lowest level of input that is

significant to the fair value measurement.

The following tables set out the classification of the methodology

used by the Company to fair value its

derivatives:

As at

December 31, 2021

millions of Canadian dollars

Level 1

Level 2

Level 3

Total

Assets

Regulatory deferral

Commodity swaps and forwards

Coal purchases

Power purchases

Natural gas purchases and sales

Heavy fuel oil purchases

Foreign exchange forwards

Physical natural gas purchases and sales

101

237

HFT derivatives

Power swaps and physical contracts

Natural gas swaps, futures, forwards, physical

contracts and related transportation

(1)

Other derivatives

Equity derivatives

Total assets

115

104

301

Liabilities

Regulatory deferral

Commodity swaps and forwards

Power purchases

Natural gas purchases and sales

Foreign exchange forwards

HFT derivatives

Power swaps and physical contracts

Natural gas swaps, futures, forwards and physical

contracts

122

515

650

127

518

662

Total liabilities

140

518

682

Net assets (liabilities)

(58)

(414)

(381)

As at

December 31, 2020

millions of Canadian dollars

Level 1

Level 2

Level 3

Total

Assets

Cash flow hedges

Interest rate hedge

Regulatory deferral

Commodity swaps and forwards

Power purchases

Natural gas purchases and sales

Heavy fuel oil purchases

HFT derivatives

Power swaps and physical contracts

Natural gas swaps, futures, forwards, physical

contracts and related transportation

Other derivatives

Foreign exchange forwards

Total assets

Liabilities

Regulatory deferral

Commodity swaps and forwards

Coal purchases

Power purchases

Heavy fuel oil purchases

Natural gas purchases and sales

Foreign exchange forwards

HFT derivatives

Power swaps and physical contracts

Natural gas swaps, futures, forwards and physical

contracts

257

268

258

275

Other derivatives

Equity derivatives

Total liabilities

258

338

Net assets (liabilities)

(26)

(244)

(240)

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

for the year ended December 31, 2021 was as

follows:

Regulatory Deferral

HFT Derivatives

millions of Canadian dollars

Physical natural

gas purchases and

sales

Power

Natural

gas

Total

Balance, January 1, 2021

Unrealized gains included in regulatory assets or

liabilities

Total

realized and unrealized gains included in

non-regulated operating revenues

Balance, December 31, 2021

104

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

the year ended December 31, 2021 was

as follows:

HFT Derivatives

millions of Canadian dollars

Power

Natural

gas

Total

Balance, January 1, 2021

257

258

Total

realized and unrealized losses included in non-regulated

operating revenues

258

260

Balance, December 31, 2021

515

518

Significant unobservable inputs used in the fair value

measurement of Emera’s natural gas and power

derivatives include third-party sourced pricing for instruments based

on illiquid markets; internally

developed correlation factors and basis differentials;

own credit risk; and discount rates. Internally

developed correlations and basis differentials

are reviewed on a quarterly basis based on statistical

analysis of the spot markets in the various illiquid term markets.

Discount rates may include a risk

premium for those long-term forward contracts with illiquid future

price points to incorporate the inherent

uncertainty of these points. Any risk premiums for long-term

contracts are evaluated by observing similar

industry practices and in discussion with industry peers.

Significant increases (decreases) in any of these

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

fair value measurement.

The following table outlines quantitative information about the

significant unobservable inputs used in the

fair value measurements categorized within Level 3 of the fair

value hierarchy:

As at

December 31, 2021

millions of Canadian dollars

Fair

Value

Valuation

Technique

Unobservable Input

Range

Weighted

average

(1)

Assets

Regulatory deferral – Physical

Modelled pricing

Third-party pricing

4.51

26.09

9.74

natural gas purchases and sales

Probability of default

2.52

% -

4.4

3.31

Discount rate

0.01

% -

1.6

0.48

HFT derivatives – Power swaps

Modelled pricing

Third-party pricing

37.05

213.00

93.60

and physical contracts

Probability of default

0.01

% -

2.52

0.45

Discount rate

0.00

% -

1.86

0.19

HFT derivatives

–

Modelled pricing

Third-party pricing

2.18

20.42

3.75

Natural gas swaps, futures,

Probability of default

0.01

% -

7.38

0.13

forwards and physical contracts

Discount rate

0.00

% -

11.98

0.37

(8)

Modelled pricing

Third-party pricing

2.83

20.86

10.85

Basis adjustment

0.00

0.44

0.42

Probability of default

0.01

% -

4.17

0.46

Discount rate

0.00

% -

1.73

0.21

Total assets

104

Liabilities

HFT derivatives

–

Modelled pricing

Third-party pricing

37.8

0 - $

145.8

111.15

Power swaps and

Own credit risk

0.01

% -

1.48

0.12

physical contracts

Discount rate

0.01

% -

1.86

0.31

Modelled pricing

Third-party pricing

37.46

126.75

95.02

Correlation factor

100% - 100%

100%

Own credit risk

0.01

% -

11.16

0.07

Discount rate

0.01

% -

1.86

0.21

HFT derivatives

–

458

Modelled pricing

Third-party pricing

1.9

0 - $

20.42

9.12

Natural gas swaps, futures,

Own credit risk

0.01

% -

7.38

0.08

forwards and physical contracts

Discount rate

0.00

% -

14.59

1.54

Modelled pricing

Third-party pricing

2.83

21.53

12.03

Basis adjustment

0.00

1.11

0.28

Own credit risk

0.01

% -

0.49

0.02

Discount rate

0.00

% -

1.73

0.13

Total liabilities

518

Net liabilities

(414)

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

As at

December 31, 2020

millions of Canadian dollars

Fair

Value

Valuation

Technique

Unobservable Input

Range

Weighted

average

(1)

Assets

HFT derivatives

–

Modelled pricing

Third-party pricing

$20.50 - $62.45

31.14

Power swaps and

Probability of default

0.02

% -

9.74

2.52

physical contracts

Discount rate

0.01

% -

0.73

0.25

Modelled pricing

Third-party pricing

$25.70 - $36.05

29.53

Probability of default

0.36

% -

0.85

0.6

Discount rate

0.06

% -

0.41

0.28

Correlation factor

100

% -

100

HFT derivatives

–

Modelled pricing

Third-party pricing

$1.66 - $6.22

2.52

Natural gas swaps, futures,

Probability of default

0.02

% -

2.52

0.4

forwards, and physical contracts

Discount rate

0.00

% -

10.36

0.75

(6)

Modelled pricing

Third-party pricing

$1.82 - $6.44

4.66

Basis adjustment

$0.00 - $1.33

0.44

Probability of default

0.02

% -

12.58

1.95

Discount rate

0.00

% -

0.67

0.13

Total assets

Liabilities

HFT derivatives

–

Modelled pricing

Third-party pricing

1.13

62.45

36.90

Power swaps and physical

contracts

Own credit risk

0.02

% -

6.85

2.02

Discount rate

0.01

% -

0.73

0.34

Modelled pricing

Third-party pricing

37.25

62.45

55.00

Own credit risk

0.36

% -

1.28

0.83

Discount rate

0.01

% -

0.40

0.31

Correlation factor

100

% -

100

100%

HFT derivatives

–

226

Modelled pricing

Third-party pricing

1.44

6.57

3.68

Natural gas swaps, futures,

Own credit risk

0.02

% -

2.52

0.10

forwards and physical contracts

Discount rate

0.00

% -

8.79

0.43

Modelled pricing

Third-party pricing

1.54

8.44

4.69

Basis adjustment

0.00

1.33

0.87

Own credit risk

0.03

% -

12.58

0.10

Discount rate

0.00

% -

0.67

0.16

Total liabilities

258

Net assets (liabilities)

(244)

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

Long-term debt is a financial liability not measured at fair value

on the Consolidated Balance Sheets. The

balance consisted of the following:

As at

Carrying

millions of Canadian dollars

Amount

Fair Value

Level 1

Level 2

Level 3

Total

December 31, 2021

14,658

16,775

16,308

467

16,775

December 31, 2020

13,721

16,487

16,020

467

16,487

The Company has designated $

1.2

billion USD denominated Hybrid Notes as a hedge of the

foreign

currency exposure of its ne

t investment

in USD denominated operations. The Company’s Hybrid Notes

are contingently convertible into preferred shares in the

event of bankruptcy or other related events. A

redemption option on or after June 15, 2026 is available

and at the control of the Company.

The Hybrid

Notes are classified as Level 2 financial assets. As at

December 31, 2021, the fair value of the Hybrid

Notes was $

1.7

billion (2020 – $

1.8

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

million was recorded

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

million).

17.

RELATED PARTY

TRANSACTIONS

In the ordinary course of business, Emera provides energy

and other services and enters into

transactions with its subsidiaries, associates and other

related companies on terms similar to those

offered to non-related parties. Intercompany balances

and intercompany transactions have been

eliminated on consolidation, except for the net profit on

certain transactions between non-regulated and

regulated entities in accordance with accounting standards

for rate-regulated entities. All material

amounts are under normal interest and credit terms.

Significant transactions

between Emera and its associated companies are as follow

●

Transactions between NSPI and NSPML

related to the Maritime Link assessment are reported

in the

Consolidated Statements of Income. NSPI’s expense

is reported in Regulated fuel for generation and

purchased power, totalling

149

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

139

million).

NSPML is accounted for as an equity investment and therefore,

the corresponding earnings related to

this revenue are reflected in Income from equity investments.

●

Natural gas transportation capacity purchases from M&NP

are reported in the Consolidated

Statements of Income. Purchases from M&NP reported

net in Operating revenues, Non-regulated,

totalled $

million for the year ended December 31, 2021 (2020

million).

There were no significant receivables or payables between

Emera and its associated companies reported

on Emera’s Consolidated Balance Sheets as at December

31, 2021 and at December 31, 2020.

18.

RECEIVABLES AND OTHER CURRENT ASSETS

Receivables and other current assets consisted of the

following:

As at

December 31

millions of Canadian dollars

2021

2020

Customer accounts receivable – billed

767

570

Customer accounts receivable – unbilled

318

286

Allowance for credit losses

(21)

(22)

Capitalized transportation capacity

(1)

316

200

Income tax receivable

Prepaid expenses

Other

280

138

1,733

1,233

(1) Capitalized transportation capacity represents the

value of transportation/storage received by EES

on asset management

agreements at the inception of the contracts. The

asset is amortized over the term of each

contract.

19.

LEASES

Lessee

The Company has operating leases for buildings, land, telecommunication services, and rail cars.

Emera’s leases have remaining lease terms of 1 year to 64 years, some of which include options to

extend the leases for up to 64 years. These options are included as part of the lease term when it is

considered reasonably certain that they will be exercised.

As at

December 31

millions of Canadian dollars

Classification

2021

2020

Right-of-use asset

Other long-term assets

Lease liabilities

Current

Other current liabilities

Long-term

Other long-term liabilities

Total

lease liabilities

The Company has recorded lease expense of $

150

million for the year ended December 31, 2021 (2020

– $

160

million), of which $

142

million (2020 – $

149

million) relates to variable costs for power generation

facility finance leases, recorded in “Regulated fuel for

generation and purchased power” in the

Consolidated Statements of Income.

Future minimum lease payments under non-cancellable operating

leases for each of the next five years

and in aggregate thereafter are as follows:

millions of Canadian dollars

2022

2023

2024

2025

2026

Thereafter

Total

Minimum lease payments

112

135

Less imputed interest

(73)

Total

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

Year ended December

For the

2021

2020

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

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

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

Operating leases (millions of Canadian dollars)

Weighted average remaining lease term (years)

Weighted average discount rate-

operating leases

3.98%

3.96%

Lessor

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

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

Direct finance and sales-type lease unearned income is recognized

in income over the life of the lease

using a constant rate of interest equal to the internal

rate of return on the lease and is recorded as

“Operating revenues – regulated gas” and “Other income,

net” on the Consolidated Statements of

Income.

The Company manages its risk associated with the residual

value of the Brunswick Pipeline lease

through proper routine maintenance of the asset.

Customers have the option to purchase CNG station assets at any time after 2021 by paying a make-

whole payment at the date of the purchase based on a targeted internal rate of return or may take

possession of the CNG station asset at the end of the lease term for no cost. Customers have the option

to purchase heat pumps at the end of the lease term for a nominal fee.

Net investment in direct finance and sales-type leases

consist of the following:

As at

December 31

millions of Canadian dollars

2021

2020

Total

minimum lease payment to be received

947

1,018

Less: amounts representing estimated executory costs

(165)

(179)

Minimum lease payments receivable

782

839

Estimated residual value of leased property (unguaranteed)

183

Less: unearned finance lease income

(443)

(487)

Net investment in direct finance and sales-type leases

522

535

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

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

assets")

Net Investment in direct finance leases - long-term

462

475

As at December 31, 2021, future minimum lease payments

to be received for each of the next five years

and in aggregate thereafter are as follows:

millions of Canadian dollars

2022

2023

2024

2025

2026

Thereafter

Total

Minimum lease payments to be

received

555

947

Less: executory costs

(165)

Total

782

20.

PROPERTY,

PLANT AND EQUIPMENT

Property, plant and

equipment consisted of the following regulated and non-regulated

assets:

As at

December 31

millions of Canadian dollars

Estimated useful life

2021

2020

Generation

131

11,173

11,474

Transmission

2,532

2,414

Distribution

6,305

5,997

Gas transmission and distribution

4,385

3,879

General plant and other

(1)

2,473

2,127

Total

cost

26,868

25,891

Less: Accumulated depreciation

(1)

(8,739)

(8,714)

18,129

17,177

Construction work in progress

(1)

2,224

2,358

Net book value

20,353

19,535

(1) SeaCoast owns a

% undivided ownership interest in a jointly

owned

-mile pipeline lateral located in Florida, which went

into

service in 2020. At December 31, 2021, SeaCoast’s

share of plant in service was $

million (2020 - $

million), and accumulated

depreciation of $

million (2020 - nil). SeaCoast’s undivided ownership

interest is financed with its funds and all operations

are

accounted for as if such participating interest were

a wholly owned facility. SeaCoast’s share of direct expenses of the jointly owned

pipeline is included in OM&G in the Consolidated

Statements of Income.

21.

EMPLOYEE BENEFIT PLANS

Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which

cover substantially all of its employees. In addition, the Company provides non-pension benefits for its

retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador,

Florida, New Mexico, Barbados, Dominica and Grand Bahama Island.

On March 24, 2020, Emera sold

Emera Maine, refer to note 4 for further detail.

Emera’s net periodic benefit cost included the following:

Benefit Obligation and Plan Assets

The changes in benefit obligation and plan assets, and the funded

status for all plans were as follows:

For the

Year ended December 31

millions of Canadian dollars

2021

2020

Change in Projected Benefit Obligation

("PBO") and Accumulated Post-

retirement Benefit Obligation ("APBO")

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Balance, January 1

2,759

339

2,822

353

Service cost

Plan participant contributions

Interest cost

Benefits paid

(160)

(27)

(135)

(27)

Actuarial gains (losses)

(89)

(10)

189

Settlements and curtailments

(229)

(52)

Foreign currency translation adjustment

(2)

(1)

(25)

(7)

Balance, December 31

2,624

318

2,759

339

Change in plan assets

Balance, January 1

2,605

2,593

Employer contributions

Plan participant contributions

Benefits paid

(160)

(27)

(135)

(27)

Actual return on assets, net of expenses

214

310

Settlements and curtailments

(191)

(7)

Foreign currency translation adjustment

(5)

(1)

(20)

(1)

Balance, December 31

2,702

2,605

Funded status, end of year

(267)

(154)

(287)

The actuarial gains recognized in the period are primarily

due to gains associated with changes in the

discount rate and demographic assumption changes. This was

partially offset by losses associated with

changes in inflation and compensation-related assumptions.

Plans with PBO/APBO

in Excess of Plan Assets

The aggregate financial position for all pension plans

where the PBO or APBO (for post-retirement benefit

plans) exceeds the plan assets for the years ended December

31 is as follows:

millions of Canadian dollars

2021

2020

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

PBO/APBO

140

290

2,736

308

Fair value of plan assets

2,568

Funded status

(105)

(290)

(168)

(308)

Plans with Accumulated Benefit Obligation (“ABO”)

in Excess of Plan Assets

The ABO for the defined benefit pension plans was $

2,507

million as at December 31, 2021 (2020 –

2,639

million). The aggregate financial position for those

plans with an ABO in excess of the plan assets

for the years ended December 31 is as follows:

millions of Canadian dollars

2021

2020

Defined benefit

pension plans

Defined benefit

pension plans

ABO

133

1,519

Fair value of plan assets

1,419

Funded status

(98)

(100)

Balance Sheet

The amounts recognized in the Consolidated Balance Sheets

consisted of the following:

As at

December 31

millions of Canadian dollars

2021

2020

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Other current liabilities

(7)

(20)

(4)

(19)

Long-term liabilities

(100)

(270)

(163)

(290)

Other long-term assets

185

Amount included in deferred income tax

(8)

(4)

(1)

AOCI and regulatory assets, net of tax

230

443

107

Net amount recognized

300

(176)

285

(183)

Amounts Recognized in AOCI and Regulatory Assets

Unamortized gains and losses and past service costs

arising on post-retirement benefits are recorded in

AOCI or regulatory assets. The following table summarizes

the change in AOCI and regulatory assets:

Regulatory assets

Actuarial

(gains) losses

millions of Canadian dollars

Defined Benefit Pension Plans

Balance, January 1, 2021

279

160

Amortized in current period

(24)

(21)

Current year addition to AOCI or regulatory assets

(61)

(109)

Change in foreign exchange rate

(2)

Balance, December 31, 2021

192

Non-pension benefits plans

Balance, January 1, 2021

110

(4)

Amortized in current period

(2)

(3)

Current year addition to AOCI or regulatory assets

(16)

Change in foreign exchange rate

(1)

Balance, December 31, 2021

2021

2020

millions of Canadian dollars

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Actuarial losses (gains)

160

(4)

Regulatory assets

192

279

110

Total

AOCI and regulatory assets before

deferred income taxes

222

439

106

Amount included in deferred income tax

assets

(1)

Net amount in AOCI and regulatory assets

230

443

107

Benefit Cost Components

Emera's net periodic benefit cost included the following:

As at

Year ended December 31

millions of Canadian dollars

2021

2020

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Service cost

Interest cost

Expected return on plan assets

(132)

(1)

(141)

(1)

Current year amortization of:

Actuarial losses (gains)

Past service costs (gains)

(1)

Regulatory assets (liability)

Total

The expected return on plan assets is determined based on

the market-related value of plan assets of

2,151

million as at January 1, 2021 (2020 – $

2,476

million), adjusted for interest on certain cash flows

during the year.

The market-related value of assets is based on a five-year smoothed asset value. Any

investment gains (or losses) in excess of (or less than) the expected return on plan assets are recognized

on a straight-line basis into the market-related value of assets over a five-year period.

Pension Plan Asset Allocations

Emera’s investment policy includes discussion

regarding the investment philosophy,

the level of risk

which the Company is prepared to accept with respect

to the investment of the Pension Funds, and the

basis for measuring the performance of the assets. Central

to the policy is the target asset allocation by

major asset categories. The objective of the target asset allocation

is to diversify risk and to achieve asset

returns that meet or exceed the plan’s actuarial

assumptions. The diversification of assets reduces the

inherent risk in financial markets by requiring that assets

be spread out amongst various asset classes.

Within each asset class, a further diversification is undertaken

through the investment in a broad range of

investment and non-investment grade securities. Emera’s

target asset allocation is as follows:

Canadian Pension Plans

Asset Class

Target

Range at Market

Short-term securities

Fixed income

35%

50%

Equities:

Canadian

12%

22%

Non-Canadian

30%

55%

Non-Canadian Pension Plans

Asset Class

Target

Range at Market

Weighted average

Fixed income

30%

50%

Equities

50%

70%

Pension Plan assets are overseen by the respective Management

Pension Committees in the sponsoring

companies. All pension investments are in accordance with policies

approved by the respective Board of

Directors of each sponsoring company.

The following tables set out the classification of the methodology

used by the Company to fair value its

investments:

millions of Canadian dollars

NAV

Level 1

Level 2

Total

Percentage

December 31, 2021

Cash and cash equivalents

Net in-transits

(84)

(3)

Equity Securities:

Canadian equity

US equity

366

Other equity

215

Fixed income securities:

Government

132

Corporate

117

Other

Mutual funds

Other

(1)

Open-ended investments

measured at NAV

(1)

952

Common collective trusts

measured at NAV

(2)

750

Total

1,702

749

251

2,702

100

December 31, 2020

Cash and cash equivalents

Net in-transits

(99)

(4)

Equity securities:

Canadian equity

154

US equity

380

Other equity

243

Fixed Income securities:

Government

119

Corporate

141

Other

Mutual funds

Other

(3)

(4)

(7)

Open-ended investments

measured at NAV

(1)

801

Common collective trusts

measured at NAV

(2)

704

Total

1,505

841

259

2,605

100

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

collective investment trusts, or pooled funds.

NAV’s are calculated daily and the funds honor subscription and redemption activity

regularly.

(2) The common collective trusts are private funds

valued at NAV.

The NAVs are calculated based on bid prices of the underlying

securities. Since the prices are not published to external

sources, NAV is used as a practical expedient. Certain funds invest

primarily in equity securities of domestic and

foreign issuers while others invest in long duration

U.S. investment grade fixed

income assets and seeks to increase return through

active management of interest rate and

credit risks. The funds honor

subscription and redemption activity regularly.

Refer to note 16 for more information on the fair value

hierarchy and inputs used to measure fair value.

Post-Retirement Benefit Plans

There are no assets set aside to pay for most of the Company’s

post-retirement benefit plans. As is

common practice, post-retirement health benefits are paid

from general accounts as required. The

primary exceptions to this is the NMGC Retiree Medical

Plan, which is fully funded.

Investments in Emera

As at December 31, 2021 and 2020, the assets related

to the pension funds and post-retirement benefit

plans do not hold any material investments in Emera or

its subsidiaries securities. However,

as a

significant portion of assets for the benefit plan are held in pooled

assets, there may be indirect

investments in these securities.

Cash Flows

The following table shows the expected cash flows for

defined benefit pension and other post-retirement

benefit plans:

millions of Canadian dollars

Defined benefit

pension plans

Non-pension

benefit plans

Expected employer contributions

2022

Expected benefit payments

2022

153

2023

162

2024

162

2025

165

2026

169

2027 – 2031

872

104

Assumptions

The following table shows the assumptions that have been

used in accounting for defined benefit

pension and other post-retirement benefit plans:

2021

2020

(weighted average assumptions)

Defined benefit

pension plans

Non-pension

benefit plans

Defined benefit

pension plans

Non-pension

benefit plans

Benefit obligation – December 31:

Discount rate - past service

3.05

2.81

2.49

2.48

Discount rate - future service

3.18

2.92

2.64

2.51

Rate of compensation increase

3.31

3.29

2.89

3.04

Health care trend

initial (next year)

5.09

5.64

ultimate

3.77

4.35

year ultimate reached

2042

2038

Benefit cost for year ended December 31:

Discount rate - past service

2.49

2.48

3.17

3.28

Discount rate - future service

2.64

2.51

3.21

3.28

Expected long-term return on plan assets

5.86

6.29

3.25

Rate of compensation increase

2.89

3.04

3.34

3.70

Health care trend

initial (current year)

5.64

5.91

ultimate

4.35

4.37

year ultimate reached

2038

Actual assumptions used differ by plan.

The expected long-term rate of return on plan assets is based on historical and projected real rates of

return for the plan’s current asset allocation, and assumed inflation. A real rate of return is determined for

each asset class. Based on the asset allocation, an overall expected real rate of return for all assets is

determined. The asset return assumption is equal to the overall real rate of return assumption added to

the inflation assumption, adjusted for assumed expenses to be paid from the plan.

The discount rate is based on high-quality long-term corporate

bonds, with maturities matching the

estimated cash flows from the pension plan.

Defined Contribution Plan

Emera also provides a defined contribution pension plan for certain

employees. The Company’s

contribution for the year ended December 31, 2021 was

million (2020 – $

million).

22.

GOODWILL

The change in goodwill for the year ended December 31

is due to the following:

millions of Canadian dollars

2021

2020

Balance, January 1

5,720

5,835

Change in foreign exchange rate

(24)

(115)

Balance, December 31

5,696

5,720

Goodwill is subject to an annual assessment for impairment

at the reporting unit level. The goodwill on

Emera’s Consolidated Balance Sheets at December

31, 2021, primarily relates to TECO Energy and

GBPC. Emera’s reporting units with goodwill

are Tampa

Electric, PGS, NMGC, and GBPC.

In 2021, Emera performed a qualitative impairment assessment

for Tampa

Electric, PGS and NMGC,

concluding that the fair value of the reporting units exceeded

their respective carrying amounts, and as

such, no quantitative assessments were performed and no

impairment charges were recognized.

Goodwill on Emera’s Consolidated Balance Sheets

at December 31, 2021, included $

million (2020 –

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

a quantitative impairment assessment

using a discounted cash flow analysis. This assessment estimated

that the fair value of the reporting unit

exceeded its carrying value, including goodwill, by approximately

per cent. Adverse changes in

assumptions used could result in a future impairment.

23.

SHORT-TERM DEBT

Emera’s short-term borrowings consist of commercial

paper issuances, advances on revolving and non-

revolving credit facilities and short-term notes. Short-term

debt and the related weighted-average interest

rates as at December 31 consisted of the following:

millions of Canadian dollars

2021

Weighted

average

interest rate

2020

Weighted

average

interest rate

Tampa Electric Company ("TEC")

Advances on term, revolving and accounts receivable facilities

945

0.58

987

0.89

Emera

Non-revolving term facility

400

0.96

400

0.94

Bank indebtedness

TECO Finance

Advances on revolving credit and term facilities

355

1.20

205

1.46

NMGC

Advances on revolving credit facilities

1.20

1.22

GBPC

Advances on revolving credit facilities

5.25

NSPI

Bank indebtedness

Short-term debt

1,742

1,625

The Company’s total short-term revolving and non-revolving

credit facilities, outstanding borrowings and

available capacity as at December 31 were as follows:

millions of Canadian dollars

Maturity

2021

2020

Tampa

Electric Company - revolving credit facility

2026

1,014

1,019

TECO Energy/TECO Finance - revolving credit facility

2026

507

509

Emera - non-revolving term facility

2022

400

TEC - term loan

2022

634

382

TEC - accounts receivable revolving credit facility

191

NMGC - revolving credit facility

2026

158

159

GBPC - revolving credit facility

on demand

Total

2,729

2,677

Less:

Advances under revolving credit and term facilities

1,735

1,624

Letters of credit issued within the credit facilities

Total

advances under available facilities

1,739

1,628

Available capacity under existing agreements

990

1,049

The weighted average interest rate on outstanding short-term

debt at December 31, 2021 was

0.83

per

cent (2020 –

1.01

per cent).

Recent Significant Financing Activity by Segment

Florida Electric Utility

On December 17, 2021, TEC entered into a $

500

million USD unsecured, non-revolving credit facility

with

a maturity date of

December 16, 2022

. The credit facility contains customary representations

and

warranties, events of default, financial and other covenants

and bears interest based on either the

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

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

On December 17, 2021, TEC amended and restated its

800

million USD revolving credit facility.

The

amendment extended the maturity date from

March 22, 2023

December 17, 2026

. There were no other

significant changes in commercial terms from the prior

agreement.

On May 25, 2021, TEC established a commercial paper

program. Amounts available under the

commercial paper program may be borrowed, repaid and reborrowed

with the aggregate amount of the

notes outstanding at any time not to exceed $

800

million USD. The full amount of commercial

paper

issued is backed by TEC’s credit facility and results

in an equal amount of its credit facility being

considered drawn and unavailable.

As a result of the $

800

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

on March 23, 2021, TEC

repaid its $

300

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

150

million USD accounts

receivable collateralized borrowing facility and the agreement

subsequently matured and terminated on

March 22, 2021.

Gas Utilities and Infrastructure

On December 17, 2021, NMGC amended and restated

its $

125

million USD revolving credit facility.

The

amendment extended the maturity date from

March 22, 2023

December 17, 2026

. There were no other

significant changes in commercial terms from the prior

agreement.

Other

On December 17, 2021, TECO Finance amended and

restated its $

400

million USD revolving credit

facility. The amendment

extended the maturity date from

March 22, 2023

December 17, 2026

. There

were no other significant changes in commercial terms

from the prior agreement.

On December 3, 2021, Emera extended the maturity date

of its $

400

million non-revolving term loan from

December 16, 2021

December 16, 2022

. There were no other significant changes in commercial

terms

from the prior agreement.

24.

OTHER CURRENT LIABILITIES

As at

December 31

millions of Canadian dollars

2021

2020

Accrued charges

157

141

Accrued interest on long-term debt

Pension and post-retirement liabilities (note 21)

Sales and other taxes payable

Income tax payable

Other

366

340

25.

LONG-TERM DEBT

Bonds, notes and debentures are at fixed interest rates

and are unsecured unless noted below.

Included

are certain bankers’ acceptances and commercial paper

where the Company has the intention and the

unencumbered ability to refinance the obligations for a period

greater than one year.

Long-term debt as at December 31 consisted of the following:

Weighted average

interest rate

(1)

millions of Canadian dollars

2021

2020

Maturity

2021

2020

Emera

Bankers acceptances, LIBOR loans

Variable

2026

378

263

Unsecured fixed rate notes

2.90%

2023

500

Fixed to floating subordinated notes (USD)

(2)

6.75%

2076

1,521

1,528

2,399

2,291

Emera Finance

Unsecured senior notes (USD)

3.65%

3.86%

2024 - 2046

3,487

3,501

TECO Finance

Tampa Electric

(3)

Fixed rate notes and bonds (USD)

4.15%

4.53%

2022 - 2051

3,683

3,268

PGS

Fixed rate notes and bonds (USD)

3.78%

4.58%

2022 - 2051

660

429

NMGC

Fixed rate notes and bonds (USD)

3.11%

4.30%

2026 - 2051

488

465

Non-revolving term facility, floating rate

Variable

2022

101

589

465

NMGI

Fixed rate notes and bonds (USD)

3.64%

2024

190

191

NSPI

Discount notes

Variable

2026

376

291

Medium term fixed rate notes

5.14%

2025 - 2097

2,665

3,041

2,956

EBP

Senior secured credit facility

Variable

2025

249

ECI

Secured senior notes (USD)

Variable

2026

106

Amortizing fixed rate notes (USD)

3.97%

3.92%

2022 - 2026

104

100

Non-revolving term facility, floating rate

Variable

2025

Non-revolving term facility, fixed rate

2.36%

2.60%

2025 - 2026

101

Secured fixed rate senior notes

(4)

4.43%

4.39%

2022 - 2035

161

174

478

476

Adjustments

Fair market value adjustment - TECO Energy acquisition

(5)

Debt issuance costs

(121)

(110)

Amount due within one year

(462)

(1,382)

(580)

(1,487)

Long-Term Debt

14,196

12,339

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

(2) In 2021, the company recognized $

102

million in interest expense (2020 - $

109

million) related to its fixed to floating

subordinated notes.

(3) A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first

mortgage bonds. There are

currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture.

(4) Notes are issued and payable in either USD,

BBD or East Caribbean Dollar (XCD).

(5) On acquisition of TECO Energy, Emera recorded a fair market value adjustment

on the unregulated long-term debt acquired.

The fair market value adjustment is amortized over

the remaining term of the debt.

The Company’s total long-term revolving credit facilities,

outstanding borrowings and available capacity as

at December 31 were as follows:

millions of Canadian dollars

Maturity

2021

2020

Emera – revolving credit facility

(1)

June 2026

900

NSPI - revolving credit facility

(1)

December 2026

600

ECI – revolving credit facilities

2022-2032

Total

1,527

1,528

Less:

Borrowings under credit facilities

770

569

Letters of credit issued inside credit facilities

124

Use of available facilities

894

600

Available capacity under existing agreements

633

928

(1) Advances on the revolving credit facility can be

made by way of overdraft on accounts up

to $

million.

Debt Covenants

Emera and its subsidiaries have debt covenants associated

with their credit facilities. Covenants are

tested regularly and the Company is in compliance with

covenant requirements. Emera’s significant

covenants are listed below:

As at

Financial Covenant

Requirement

December 31, 2021

Emera

Syndicated credit facilities

Debt to capital ratio

Less than or equal to

0.70

to 1

0.57

: 1

Recent Significant Financing Activity by Segment

Florida Electric Utility

On May 15, 2021, TEC repaid its $

278

million USD,

5.4

per cent notes upon maturity.

The notes were

repaid using existing credit facilities.

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

800

million USD senior notes. The issuance

included $

400

million USD senior notes that bear interest at a rate

2.40

per cent with a maturity date of

March 15, 2031

and $

400

million USD senior notes that bear interest at a rate of

3.45

per cent with a

maturity date of

March 15, 2051

Canadian Electric Utilities

On December 3, 2021, NSPI amended its operating credit

facility to extend the maturity from

October

2024

December 2026

. There were no other significant changes in commercial

terms from the prior

agreement.

Other Electric

On December 16, 2021, GBPC entered into a $

million USD

4.00

per cent term loan with a maturity

date of

December 31, 2026

. Proceeds from this loan were used to repay existing,

non-revolving term

loans totaling $

million USD and to fund operations.

Gas Utilities and Infrastructure

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

of its $

250

million credit facility from

May 17, 2023

June 30, 2025

. There were no other significant changes in commercial

terms from the

prior agreement.

On March 25, 2021, NMGC entered into a $

100

million USD unsecured, non-revolving credit facility

with a

maturity date of

September 23, 2022

. The credit facility contains customary representations

and

warranties, events of default, financial and other covenants

and bears interest based on either the LIBOR,

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

On February 5, 2021, NMGC completed an issuance of

220

million USD senior notes. The issuance

included $

million USD senior notes that bear interest at a rate

2.26

per cent with a maturity date of

February 5, 2031

, $

million USD senior notes that bear interest at a rate

2.51

per cent and with a

maturity date of

February 5, 2036

, and $

million USD senior notes that bear interest at a

rate of

3.34

per cent with a maturity date of

February 5, 2051

. Proceeds from this issuance were used to repay

200

million USD note due in 2021, which was classified as

long-term debt at December 31, 2020.

Other

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

its $

900

million unsecured committed revolving

credit facility from

June 30, 2024

June 30, 2026

. There were no other significant changes in

commercial terms from the prior agreement.

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

of $

750

million USD senior notes. The

issuance included $

450

million USD senior notes that bear interest at a rate of

2.64

per cent with a

maturity date of

June 15, 2031

and $

300

million USD senior notes that bear interest at a rate

0.83

per

cent with a maturity date of

June 15, 2024

. The USD senior notes are guaranteed by Emera

and Emera

US Holdings Inc., a wholly owned Emera subsidiary.

From the $

750

million USD senior notes issuance discussed above, on

June 15, 2021, Emera US

Finance LP repaid its previously outstanding $

750

million USD senior notes on maturity.

Long-Term Debt Maturities

As at December 31, long-term debt maturities, including capital

lease obligations, for each of the next five

years and in aggregate thereafter are as follows:

millions of Canadian dollars

2022

2023

2024

2025

2026

Thereafter

Total

Emera

500

1,899

2,399

Emera US Finance LP

571

951

1,965

3,487

Tampa

Electric

285

3,398

3,683

PGS

628

660

NMGC

101

399

589

NMGI

190

NSPI

125

416

2,500

3,041

EBP

249

ECI

130

124

478

Total

462

590

827

504

3,479

8,914

14,776

26.

ASSET RETIREMENT OBLIGATIONS

AROs mostly relate to reclamation of land at the thermal, hydro

and combustion turbine sites; and the

disposal of polychlorinated biphenyls in transmission and

distribution equipment and a pipeline site.

Certain hydro, transmission and distribution assets may have additional

AROs that cannot be measured

as these assets are expected to be used for an indefinite

period and, as a result, a reasonable estimate of

the fair value of any related ARO cannot be made.

The change in ARO for the years ended December 31

is as follows:

millions of Canadian dollars

2021

2020

Balance, January 1

178

185

Additions

Liabilities settled

(1)

(13)

(25)

Accretion included in depreciation expense

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

(2)

(3)

Other

Change in foreign exchange rate

(1)

Balance, December 31

174

178

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

its Big Bend and Polk power stations. The

decreases in ARO in 2021 and 2020 are due

to the closure of CCR management facilities.

27.

COMMITMENTS AND CONTINGENCIES

Commitments

As at December 31, 2021, contractual commitments (excluding

pensions and other post-retirement

obligations, long-term debt and asset retirement obligations) for

each of the next five years and in

aggregate thereafter consisted of the following:

millions of Canadian dollars

2022

2023

2024

2025

2026

Thereafter

Total

Transportation

(1)

563

437

372

323

297

2,627

4,619

Purchased power

(2)

231

227

244

242

235

1,967

3,146

Fuel, gas supply and storage

694

104

908

Capital Projects

359

457

Long-term service agreements

(3)

303

Equity investment commitments

(4)

240

Leases and other

(5)

116

175

Demand side management

2,195

942

726

650

588

4,793

9,894

(1)

Purchasing commitments for transportation of

fuel and transportation capacity on various pipelines. Includes

a commitment of

142

million related to a gas transportation contract between

PGS and SeaCoast through 2040.

(2)

Annual requirement to purchase electricity

production from IPPs or other utilities over

varying contract lengths.

(3)

Maintenance of certain generating equipment,

services related to a generation facility and

wind operating agreements,

outsourced management of computer and communication

infrastructure and vegetation management.

(4)

Emera has a commitment to make equity

contributions to the LIL.

(5)

Includes operating lease agreements for buildings,

land, telecommunications services and rail cars, transmission

rights and

investment commitments.

NSPI has a contractual obligation to pay NSPML for the

use of the Maritime Link over approximately

years

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

2020 through 2022 fuel stability plan,

rates have been set to include $

164

million and $

162

million for 2021 and 2022, respectively.

The timing

and amounts payable to NSPML for the remainder of

the

-year commitment period are subject to

UARB approval. Any difference between the amounts

included in the NSPI fuel stability plan and those

approved by the UARB through the NSPML interim assessment

application will be addressed through the

FAM. On August 9, 2021,

NSPML filed a final capital cost application with the UARB

seeking approval to

recover capital costs associated with the Maritime Link

and approval of NSPML’s

2022 assessment.

December 2021, NSPML obtained an interim decision

from the UARB approving interim rates beginning

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

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

issued its decision relating to the Maritime Link Project,

approving NSPML’s

requested rate base of

approximately $

1.8

billion less costs that would not otherwise have been recoverable

if incurred by NSPI.

For further information on the UARB decision, refer to

note

Once Muskrat Falls and LIL have achieved full power,

the commercial agreements between Emera and

Nalcor require true ups to finalize the respective investment

obligations of the parties relating to the

Maritime Link and LIL.

Emera has committed to obtain certain transmission rights

for Nalcor, if requested,

to enable it to transmit

energy which is not otherwise used in Newfoundland and Labrador

or Nova Scotia. Nalcor has the right to

transmit this energy from Nova Scotia to New England

energy markets effective August 15, 2021, the

date the NS Block commenced, and continuing for

50 years

. As transmission rights are contracted, the

obligations are included within “Leases and other” in the

above table.

Legal Proceedings

TECO Guatemala Holdings (“TGH”)

Prior to Emera’s acquisition of TECO Energy in 2016,

TGH, a wholly owned subsidiary of TECO Energy,

divested of its indirect investment in the Guatemala electricity

sector, but retained certain claims

against

the Republic of Guatemala (“Guatemala”). In 2013, TGH

asserted an arbitration claim against Guatemala

with the International Centre for the Settlement of Investment

Disputes (“ICSID”) under the Dominican

Republic Central America – United States Free Trade

Agreement. The arbitration concerned TGH’s

allegation that Guatemala unfairly set the distribution tariff

for a local distribution company which harmed

TGH’s investment in that company.

A tribunal established by the ICSID ruled in favour of TGH

(the “First

Award”) and in November 2020, Guatemala made

a payment of approximately $

million USD in full and

final satisfaction of the First Award.

On September 23, 2016, TGH had filed a request for resubmission

to arbitration seeking damages in

addition to those awarded in the First Award. On

May 13, 2020, an ICSID tribunal awarded TGH

additional damages and costs against Guatemala of more than

million USD plus interest (the

“Second Award”). TGH subsequently requested a reconsideration

of the interest quantum awarded in

connection with this Second Award. On October

16, 2020, the tribunal granted TGH’s request

for

additional interest. The additional amount is approximately $

million USD. On February 12, 2021,

Guatemala filed an application for annulment of the Second

Award with ICSID. On March 31, 2021, ICSID

constituted an ad hoc Committee to oversee the annulment proceeding.

On May 17, 2021, the ad hoc

Committee issued (i) a decision continuing the stay of

enforcement of the Second Award until the

committee renders its decision on Guatemala’s

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

briefings on the annulment and a hearing commencing July 27,

2022.

Guatemala filed its Memorial on

Annulment on August 25, 2021.

TGH’s Counter-Memorial on Annulment was filed

on December 8, 2021.

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

is approximately $

million USD. Results to date

do not reflect any benefit of the Second Award.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa

Electric and PGS divisions, is a potentially responsible

party (“PRP”) for certain

superfund sites and, through its PGS division, for certain former

manufactured gas plant sites. While the

joint and several liability associated with these sites presents

the potential for significant response costs,

as at December 31, 2021, TEC has estimated its financial

liability to be $

million ($

million USD),

primarily at PGS. This estimate assumes that other involved

PRPs are credit-worthy entities. This amount

has been accrued and is primarily reflected in the long-term

liability section under “Other long-term

liabilities” on the Consolidated Balance Sheets. The environmental

remediation costs associated with

these sites are expected to be paid over many years.

The estimated amounts represent only the portion of the cleanup

costs attributable to TEC. The estimates

to perform the work are based on TEC’s experience

with similar work, adjusted for site-specific conditions

and agreements with the respective governmental agencies.

The estimates are made in current dollars,

are not discounted and do not assume any insurance

recoveries.

In instances where other PRPs are involved, most of those

PRPs are believed to be currently credit-

worthy and are likely to continue to be credit-worthy for

the duration of the remediation work. However,

those instances that they are not, TEC could be liable for

more than TEC’s actual percentage of the

remediation costs. Other factors that could impact these

estimates include additional testing and

investigation which could expand the scope of the cleanup activities,

additional liability that might arise

from the cleanup activities themselves or changes in

laws or regulations that could require additional

remediation. Under current regulations, these costs are recoverable

through customer rates established

in base rate proceedings.

Other Legal Proceedings

Emera and its subsidiaries may,

from time to time, be involved in other legal proceedings,

claims and

litigation that arise in the ordinary course of business

which the Company believes would not reasonably

be expected to have a material adverse effect on the

financial condition of the Company.

Principal Financial Risks and Uncertainties

Emera believes the following principal financial risks could materially

affect the Company in the normal

course of business. Risks associated with derivative instruments

and fair value measurements are

discussed in note 15 and note 16.

Sound risk management is an essential discipline for running

the business efficiently and pursuing the

Company’s strategy successfully.

Emera has a business-wide risk management process, monitored

the Board of Directors, to ensure a consistent and coherent

approach to risk management. The Board of

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

in September 2021. The mandate of

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

sustainability oversight responsibilities and

includes oversight of the Company’s Enterprise Risk

Management framework, including the identification,

assessment, monitoring and management

of enterprise risks.

Public Health Risk

An outbreak of infectious disease, a pandemic or a similar

public health threat, such as the COVID-19

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

impact the Company,

including causing

operating, supply chain and project development delays

and disruptions, labour shortages and shutdowns

(including as a result of government regulation and

prevention measures), which could have a negative

impact on the Company’s operations.

Any adverse changes in general economic and market conditions

arising as a result of a public health

threat could negatively impact demand for electricity and natural

gas, revenue, operating costs, timing

and extent of capital investments, results of financing

efforts, or credit risk and counterparty risk;

which

could result in a material adverse

effect on the Company’s business. The

Company maintains pandemic

and business contingency plans in each of its operations

to manage and help mitigate the impact of any

such public health threat.

Foreign Exchange Risk

The Company is exposed to foreign currency exchange rate changes.

Emera operates internationally,

with an increasing amount of the Company’s net income

earned outside of Canada. As such, Emera is

exposed to movements in exchange rates between the

Canadian dollar and, particularly,

the US dollar,

which could positively or adversely affect results.

Consistent with the Company’s risk management

policies, Emera manages currency risks through

matching US denominated debt to finance its US operations

and may use foreign currency derivative

instruments to hedge specific transactions and earnings

exposure. The Company may enter foreign

exchange forward and swap contracts to limit exposure on certain

foreign currency transactions such as

fuel purchases, revenue streams and capital investment

s, and on net income earned outside of Canada.

The regulatory framework for the Company’s rate

-regulated subsidiaries permits the recovery of prudently

incurred costs, including foreign exchange.

The Company does not utilize derivative financial instruments

for foreign currency trading or speculative

purposes or to hedge the value of its investments in foreign subsidiaries.

Exchange gains and losses on

net investments in foreign subsidiaries do not impact net income

as they are reported in AOCI.

Liquidity and Capital Market Risk

Liquidity risk relates to Emera’s ability to ensure sufficient

funds are available to meet its financial

obligations. Emera manages this risk by forecasting cash

requirements on a continuous basis to

determine whether sufficient funds are available.

Liquidity and capital needs could be financed through

internally generated cash flows, asset sales, short-term credit

facilities, and ongoing access to capital

markets. The Company reasonably expects liquidity sources

to exceed capital needs.

Emera’s access to capital and cost of borrowing

is subject to several risk factors, including financial

market conditions, market disruptions, and ratings assigned

by credit rating agencies. Disruptions in

capital markets could prevent Emera from issuing new

securities or cause the Company to issue

securities with less than preferred terms and conditions.

Emera’s growth plan requires significant capital

investments in property,

plant and equipment and the risk associated with changes

in interest rates could

have an adverse effect on the cost of financing. The

Company’s future access to capital and cost

borrowing may be impacted by various market disruptions. The

inability to access cost-effective capital

could have a material impact on Emera’s ability

to fund its growth plan.

Emera is subject to financial risk associated with changes

in its credit ratings. There are a number of

factors that rating agencies evaluate to determine credit

ratings, including the Company’s business

and

regulatory framework, the ability to recover costs and earn

returns, diversification, leverage, liquidity and

increased exposure to climate change-related impacts, including

increased frequency and severity of

hurricanes and other severe weather events. A decrease

in a credit rating could result in higher interest

rates in future financings, increased borrowing costs under

certain existing credit facilities, limit access to

the commercial paper market or limit the availability of

adequate credit support for subsidiary operations.

For certain derivative instruments, if the credit ratings of the

Company were reduced below investment

grade, the full value of the net liability of these positions

could be required to be posted as collateral.

Emera manages these risks by actively monitoring and managing

key financial metrics with the objective

of sustaining investment grade credit ratings.

The Company has exposure to its own common share

price through the issuance of various forms of

stock-based compensation, which affect earnings

through revaluation of the outstanding units every

period. The Company uses equity derivatives to reduce

the earnings volatility derived from stock-based

compensation.

Interest Rate Risk

Emera utilizes a combination of fixed and floating rate debt financing

for operations and capital

investments, resulting in an exposure to interest rate risk.

Emera seeks to manage interest rate risk

through a portfolio approach that includes the use of fixed

and floating rate debt with staggered

maturities. The Company will, from time to time, issue long-term

debt or enter interest rate hedging

contracts to limit its exposure to fluctuations in floating

interest rate debt.

For Emera’s regulated subsidiaries, the cost of

debt is a component of rates and prudently incurred debt

costs are recovered from customers. Regulatory ROE

will generally follow the direction of interest rates,

such that regulatory ROE’s are likely to fall in

times of reducing interest rates and rise in times of

increasing interest rates, albeit not directly and generally with

a lag period reflecting the regulatory

process. Rising interest rates may also negatively affect

the economic viability of project development

and acquisition initiatives.

Commodity Price Risk

The Company’s utility fuel supply is subject to

commodity price risk. In addition, Emera Energy is subject

to commodity price risk through its portfolio of commodity

contracts and arrangements.

The Company manages this risk through established

processes and practices to identify,

monitor, report

and mitigate these risks. The Company’s commercial

arrangements, including the combination of supply

and purchase agreements, asset management agreements,

pipeline transportation agreements and

financial hedging instruments are all used to manage and

mitigate this risk. In addition, its credit policies,

counterparty credit assessments, market and credit position

reporting, and other risk management and

reporting practices, are also used to manage and mitigate

this risk.

Regulated Utilities

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

from international suppliers and therefore may

be exposed to broader global conditions, which may include

impacts on delivery reliability and price,

despite contracted terms. The Company seeks to manage this

risk using financial hedging instruments

and physical contracts and through contractual protectio

with counterparties, where applicable.

The majority of Emera’s regulated electric and gas

utilities have adopted and implemented fuel

adjustment mechanisms and purchased gas adjusted

mechanisms respectively,

which has further helped

manage commodity price risk, as the regulatory framework

for the Company’s rate-regulated subsidiaries

permits the recovery of prudently incurred fuel and gas

costs.

Emera Energy Marketing and Trading

Emera Energy has employed further measures to manage

commodity risk. The majority of Emera

Energy’s portfolio of electricity and gas marketing

and trading contracts and, in particular,

its natural gas

asset management arrangements, are contracted on a

back-to-back basis, avoiding any material long or

short commodity positions. However,

the portfolio is subject to commodity price risk,

particularly with

respect to basis point differentials between relevant

markets, in the event of an operational issue or

counterparty default.

measure commodity price risk exposure, Emera Energy employs

a number of controls and processes,

including an estimated value-at-risk (“VaR”)

analysis of its exposures. The VaR

amount represents an

estimate of the potential change in fair value that could

occur from changes in Emera Energy’s portfolio

changes in market factors within a given confidence level, if an

instrument or portfolio is held for a

specified time period. The VaR

calculation is used to quantify exposure to market

risk associated with

physical commodities, primarily natural gas and power

positions.

Income Tax Risk

The computation of the Company’s provision for

income taxes is impacted by changes in tax legislation

Canada, the United States and the Caribbean. Any such

changes could affect the Company’s

future

earnings, cash flows, and financial position. The value

of Emera’s existing deferred tax assets and

liabilities are determined by existing tax laws and could

be negatively impacted by changes in laws.

Emera monitors the status of existing tax laws to ensure

that changes impacting the Company are

appropriately reflected in the Company’s tax compliance

filings and financial results.

Guarantees and Letters of Credit

Emera has guarantees and letters of credit on behalf of third

parties outstanding. The following significant

guarantees and letters of credit are not included within

the Consolidated Balance Sheets as at December

31, 2021:

TECO Energy has issued a guarantee in connection with

SeaCoast’s performance of obligations

under a

gas transportation precedent agreement. The guarantee is for

a maximum potential amount of $

million

USD if SeaCoast fails to pay or perform under the contract.

The guarantee expires five years after the

gas transportation precedent agreement termination date, which

was terminated on January 1, 2022. In

the event that TECO Energy’s and Emera’s

long-term senior unsecured credit ratings are downgraded

below investment grade by Moody’s or S&P,

TECO Energy would be required to provide its counterparty

a letter of credit or cash deposit of $

million USD.

Emera Inc. has issued a guarantee of up to $

million USD

relating to outstanding notes of GBPC

. The

guarantee for the notes will

expire in May 2023

In 2021, NSPI issued guarantees in the amount of $

million USD on behalf of its subsidiary,

NS Power

Energy Marketing Incorporate (“NSPEMI”), to secure

obligations under purchase agreements with third-

party suppliers and $

million USD related to a

-year natural gas transportation commitment. NSPI

has $

118

million USD (2020 - $

million USD) of guarantees outstanding with terms

of varying lengths

and will be renewed as required.

The Company has standby letters of credit and surety

bonds in the amount of $

148

million USD

(December 31, 2020 - $

million USD) to third parties that have extended credit to Emera

and its

subsidiaries. These letters of credit and surety bonds typically

have a one-year term and are renewed

annually as required.

Emera Inc., on behalf of NSPI, has a standby letter of

credit to secure obligations under a supplementary

retirement plan. The expiry date of this letter of credit was

extended to June 2022. The amount committed

as at December 31, 2021 was $

million (December 31, 2020 - $

million).

Collaborative Arrangements

For the years ended December 31, 2021 and 2020, the

Company has identified the following material

collaborative arrangements:

Through NSPI, the Company is a participant in three

wind energy projects in Nova Scotia. The

percentage ownership of the wind project assets is based on

the relative value of each party’s project

assets by the total project assets. NSPI has power

purchase arrangements to purchase the entire net

output of the projects and, therefore, NSPI’s portion

of the revenues are recorded net within regulated fuel

for generation and purchased power.

NSPI’s portion of operating expenses is recorded

in OM&G

expenses. In 2021, NSPI recognized $

million net expense (2020 - $

million) in “Regulated fuel for

generation and purchased power” and $

million (2020 - $

million) in OM&G.

28.

CUMULATIVE PREFERRED STOCK

Authorized:

Unlimited number of First Preferred shares, issuable in

series.

Unlimited number of Second Preferred shares, issuable in

series.

December 31, 2021

December 31, 2020

Annual Dividend

Redemption

Issued and

Net

Issued and

Net

Per Share

Price per share

Outstanding

Proceeds

Outstanding

Proceeds

Series A

0.5456

25.00

4,866,814

119

4,866,814

119

Series B

Floating

25.00

1,133,186

Series C

1.1802

25.00

10,000,000

245

10,000,000

245

Series E

1.1250

25.25

5,000,000

122

5,000,000

122

Series F

1.0505

25.00

8,000,000

195

8,000,000

195

Series H

1.2250

25.00

12,000,000

295

12,000,000

295

Series J

1.0625

25.00

8,000,000

196

Series L

1.1500

25.00

9,000,000

222

Total

58,000,000

1,422

41,000,000

1,004

First Preferred Shares, Series J

On April 6, 2021, Emera issued

million,

4.25

per cent Cumulative Minimum Rate Reset First Preferred

Shares, Series J

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

25.00

per share for gross proceeds of $

200

million ($

196

million, net of after-tax issuance costs).

First Preferred Shares, Series L

On September 24, 2021, Emera issued

million,

4.60

per cent Cumulative Redeemable First Preferred

Shares, Series L

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

25.00

per share for gross proceeds of $

225

million ($

222

million, net of after-tax issuance costs).

Characteristics of the First Preferred Shares:

First Preferred Shares

(1)(2)

Initial Yield

(%)

Current

Annual

Dividend

($)

Minimum

Reset

Dividend

Yield (%)

Earliest Redemption

and/or Conversion

Option Date

Redemption

Value

($)

Right to

Convert on

a one for

one basis

Fixed rate reset

(3)(4)

Series A

4.400

0.5456

1.84

August 15, 2025

25.00

Series B

Series C

4.100

1.1802

2.65

August 15, 2023

25.00

Series D

Series F

4.202

1.0505

2.63

February 15, 2025

25.00

Series G

Minimum rate reset

(3)(4)

Series B

2.393

Floating

1.84

August 15, 2025

25.00

Series A

Series H

4.900

1.2250

4.90

August 15, 2023

25.00

Series I

Series J

4.250

1.0625

4.25

May 15, 2026

25.00

Series K

Perpetual fixed rate

Series E

(5)

4.500

1.1250

25.25

Series L

(6)

4.600

1.1500

November 15, 2026

25.00

(1) Holders are entitled to receive fixed or floating

cumulative cash dividends when declared by the

Board of Directors of the

Corporation.

(2) On or after the specified redemption dates,

the Corporation has the option to redeem

for cash the outstanding First Preferred

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

share redemption value plus all accrued and

unpaid dividends up to but excluding the

dates fixed for redemption.

(3) On the redemption and/or conversion option

date the reset annual dividend per share will be

determined by multiplying $

25.00

per

share by the annual fixed or floating dividend

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

the sum of the five-year Government of Canada

Bond Yield on the applicable reset date, plus the applicable

reset dividend yield (Series H annual reset

rate must be a minimum of

4.90

per cent) and for Series B equals the Government

of Treasury Bill Rate on the applicable reset date, plus

1.84

per cent.

(4) On each conversion option date, the holders

have the option, subject to certain conditions,

to convert any or all of their Shares

into an equal number of Cumulative Redeemable

First Preferred Shares of a specified series.

The Company has the right to redeem

the outstanding Preferred Shares, Series D, Series

G and Series I shares without the consent

of the holder every five years thereafter

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

25.00

per share plus all accrued and unpaid

dividends up to but excluding the date fixed for

redemption and $

25.50

per share plus all accrued and unpaid

dividends up to but excluding the date

fixed for redemption in the case

of redemptions on any other date after August 15,

2023, February 15, 2025 and August 15, 2023,

respectively. The reset dividend

yield for Series I equals the Government of Treasury Bill Rate

on the applicable reset date, plus

2.54

per cent.

(5) First Preferred Shares, Series E are redeemable

at $

25.25

to August 15, 2022 and $

25.00

per share thereafter.

(6) First Preferred Shares, Series L are redeemable

at $

26.00

on or after November 15, 2026 to November

15, 2027, decreasing

0.25

each year until November 15, 2030 and $

25.00

per share thereafter.

First Preferred Shares are neither redeemable at the option of the shareholder nor have a mandatory

redemption date. They are classified as equity and the associated dividends is deducted on the

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

and is shown on the Consolidated Statement of Equity as a deduction from retained earnings.

The First Preferred Shares of each series rank on a parity with the First Preferred Shares of every other

series and are entitled to a preference over the Second Preferred Shares, the Common Shares, and any

other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the

distribution of the remaining property and assets or return of capital of the Company in the liquidation,

dissolution or wind-up, whether voluntary or involuntary.

In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First

Preferred Shares, the holders of the First Preferred Shares, for only so long as the dividends remain in

arrears, will be entitled to attend any meeting of shareholders of the Company at which directors are to be

elected and to vote for the election of two directors out of the total number of directors elected at any such

meeting.

29.

NON-CONTROLLING INTEREST IN SUBSIDIARIES

As at

December 31

millions of Canadian dollars

2021

2020

Preferred shares of GBPC

Domlec

Preferred shares of GBPC:

Authorized:

10,000 non-voting cumulative redeemable variable perpetual

preferred shares.

2021

2020

Issued and outstanding:

number of

millions of

dollars

number of

millions of

dollars

Outstanding as at December 31

10,000

GBPC Non–Voting

Cumulative Variable

Perpetual Preferred Stock:

The preferred shares are redeemable by GBPC after June 17, 2021

, at $

1,000

Bahamian per share plus

accrued and unpaid dividends and are entitled to a

6.0

per cent per annum fixed cumulative preferential

dividend to be paid semi-annually.

The Preferred Shares rank behind GBPC’s current

and future secured and unsecured debt and ahead of

all of GBPC’s current and future common stock.

SUPPLEMENTARY

INFORMATION TO CONSOLIDATED

STATEMENTS

CASH FLOWS

For the

Year ended December 31

millions of Canadian dollars

2021

2020

Changes in non-cash working capital:

Inventory

(84)

Receivables and other current assets

(364)

187

Accounts payable

289

Other current liabilities

(31)

Total

non-cash working capital

(152)

217

Supplemental disclosure of cash paid (received):

Interest

603

679

Income taxes

(148)

Supplemental disclosure of non-cash activities:

Common share dividends reinvested

214

199

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

256

(Decrease) Increase in accrued capital expenditures

(45)

31.

STOCK-BASED COMPENSATION

Employee Common Share Purchase Plan and Common Shareholders

Dividend

Reinvestment and Share Purchase Plan

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

December 31, 2021, the plan allows employees to make cash contributions of a minimum of $25 to a

maximum of $20,000 CAD or $15,000 USD per year for the purpose of purchasing common shares of

Emera. The Company also contributes 20 per cent of the employees’ contributions to the plan.

The plan allows the reinvestment of dividends for all participants except for where it is prohibited by law.

The maximum aggregate number of Emera common shares

reserved for issuance under this plan is

million common shares (2020 –

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

Emera is in

compliance with this requirement.

Compensation cost for shares issued by Emera for the year

ended December 31, 2021 under the

Employee Common Share Purchase Plan was $

million (2020 – $

million) and is included in OM&G on

the Consolidated Statements of Income.

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

(“Dividend Reinvestment Plan”) or (“DRIP”), which provides an opportunity for shareholders to reinvest

dividends and purchase common shares. This plan provides for a discount of up to 5 per cent from the

average market price of Emera’s common shares for common shares purchased in connection with the

reinvestment of cash dividends. The discount was 2 per cent in 2021.

Stock-Based Compensation Plans

Stock Option Plan

The Company has a stock option plan that grants options to senior management of the Company for a

maximum term of 10 years. The option price of the stock options is the closing market price of the stocks

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

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

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

date of the grant. If an option is not exercised within 10 years, it expires and the optionee loses all rights

thereunder. The holder of the option has no rights as a shareholder until the option is exercised and

shares have been issued. The total number of stocks to be optioned to any optionee shall not exceed five

per cent of the issued and outstanding common stocks on the date the option is granted.

Unless a stock option has expired, vested options may

be exercised within the

27 months

following the

option holders date of retirement, six months following

a termination without

just cause or death, and

within

sixty days

following the date of termination for just cause or

resignation. If stock options are not

exercised within such time, they expire.

The Company uses the Black-Scholes valuation model to estimate the compensation expense related to

its stock-based compensation and recognizes the expense over the vesting period on a straight-line

basis.

The following table shows the weighted average fair values

per stock option along with the assumptions

incorporated into the valuation models for options granted, for

the year-ended December 31:

2021

2020

Weighted average fair value per option

3.63

3.58

Expected term

(1)

years

Risk-free interest rate

(2)

0.60

1.33

Expected dividend yield

(3)

5.00

4.09

Expected volatility

(4)

19.14

14.10

(1) The expected term of the option awards is

calculated based on historical exercise behaviour

and represents the period of time

that the options are expected to be outstanding.

(2) Based on the Bank of Canada five-year government

bond yields.

(3) Incorporates current dividend rates and historical

dividend increase patterns.

(4) Estimated using the five-year historical volatility.

The following table summarizes stock option information

for 2021:

Total

Options

Non-Vested Options

(1)

Number of

Options

Weighted

average exercise

price per share

Number of

Options

Weighted

average grant

date fair-value

Outstanding as at December 31, 2020

2,267,782

46.62

1,293,850

2.69

Granted

653,600

51.12

653,600

3.63

Exercised

(331,078)

40.97

N/A

Vested

N/A

(494,975)

2.49

Options outstanding December 31, 2021

2,590,304

48.48

1,452,475

3.18

Options exercisable December 31, 2021

(2)(3)

1,137,829

44.86

(1) As at December 31, 2021, there was $

million of unrecognized compensation related to

stock options not yet vested which is

expected to be recognized over a weighted

average period of approximately

years (2020 - $

million,

years).

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

average remaining term of vested options was

years with an aggregate intrinsic value of

million (2020 - $

million,

years).

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

options that vested in the year was $

million (2020 - $

million).

Compensation cost recognized for stock options for the year

ended December 31, 2021 was $

million

(2020 – $

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

Statements of Income.

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

was $

million (2020 – $

million). The

total intrinsic value of options exercised for the year ended

December 31, 2021 was $

million (2020 – $

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

as at December 31, 2021 was $

32.35

60.03

(2020 – $

32.06

to $

60.03

Share Unit Plans

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

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

Deferred Share Unit Plans

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

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

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

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

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

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

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

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

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

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

redeemed.

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

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

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

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

the applicable guidelines are met.

When incentive awards are determined, the amount elected is converted to DSUs, which have a value

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

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

on an equivalent number of Emera common shares. Following termination of employment or retirement,

and by December 15 of the calendar year after termination or retirement, the value of the DSUs credited

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

by the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date.

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

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

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

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

A summary of the activity related to employee and director

DSUs for the year ended December 31, 2021

is presented in the following table:

Employee

DSU

Weighted

Average

Grant Date

Fair Value

Director

DSU

Weighted

Average

Grant Date

Fair Value

Outstanding as at December 31, 2020

661,998

37.17

591,124

41.69

Granted including DRIP

93,710

49.64

101,403

51.25

Exercised

(145,107)

36.61

(78,162)

37.57

Outstanding and exercisable as at December 31, 2021

610,601

39.22

614,365

43.80

Compensation cost recognized for employee and director

DSU’s for the year ended December 31, 2021

was $

million (2020 – $

million). Tax

benefits related to this compensation cost for share

units realized

for the year ended December 31, 2021 were $

million (2020 – $

million). The aggregate intrinsic value

of the outstanding shares for the year ended December

31, 2021 for employees was $

million (2020 -

million). The aggregate intrinsic value of the outstanding

shares for the year ended December 31,

2021 for directors was $

million (2020 - $

million). Cash payments made during the year ended

December 31, 2021 associated with the DSU plan was

million (2020 - $

million).

Performance Share Unit Plan

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

through the PSU plan. PSUs are granted annually for three -year overlapping performance cycles,

resulting in a cash payment. PSUs are granted based on the average of Emera’s stock closing price for

the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the

form of additional PSUs. The PSU value varies according to the Emera common share market price and

corporate performance.

PSUs vest at the end of the three -year cycle and the payouts will be calculated and approved by the

MRCC early in the following year. The value of the payout considers actual service over the performance

cycle and may be pro-rated in certain departure scenarios.

A summary of the activity related to employee PSUs for

the year ended December 31, 2021 is presented

in the following table:

Employee PSU

Weighted Average

Grant Date Fair Value

Aggregate intrinsic value

Outstanding as at December 31, 2020

1,126,529

47.16

Granted including DRIP

323,610

52.83

Exercised

(464,290)

48.13

Forfeited

(33,914)

47.78

Outstanding as at December 31, 2021

951,935

48.60

Compensation cost recognized for the PSU plan for the

year ended December 31, 2021 was $

million

(2020 – $

million). Tax

benefits related to this compensation cost for share

units realized for the year

ended December 31, 2021 were $

million (2020 – $

million). Cash payments made during the year

ended December 31, 2021 associated with the PSU plan was

million (2020 – $

million).

Restricted Share Unit Plan

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

through the RSU plan. RSUs are granted annually for three -year overlapping performance cycles,

resulting in a cash payment. RSUs are granted based on the average of Emera’s stock closing price for

the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the

form of additional RSUs. The RSU value varies according to the Emera common share market price.

RSUs vest at the end of the three -year cycle and the payouts will be calculated and approved by the

MRCC early in the following year. The value of the payout considers actual service over the performance

cycle and may be pro-rated in certain departure scenarios.

A summary of the activity related to employee RSUs for

the year ended December 31, 2021 is presented

in the following table:

Employee RSU

Weighted Average

Grant Date Fair Value

Aggregate intrinsic value

Outstanding as at December 31, 2020

166,275

54.62

Granted including DRIP

184,498

54.66

Exercised

(232)

54.62

Forfeited

(6,589)

54.63

Outstanding as at December 31, 2021

343,952

54.64

Compensation cost recognized for the RSU plan for the

year ended December 31, 2021 was $

million

(2020 – $

million). Tax

benefits related to this compensation cost for share

units realized for the year

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

million). Cash payments made during the year

ended December 31, 2021 associated with the RSU plan was

nil (2020–

nil

32.

VARIABLE INTEREST ENTITIES

Emera holds a variable interest in NSPML, a VIE for which

it was determined that Emera is not the

primary beneficiary since it does not have the controlling

financial interest of NSPML. When the critical

milestones were achieved, Nalcor Energy was deemed the

primary beneficiary of the asset for financial

reporting purposes as it has

authority over the majority of the direct activities that

are expected to most

significantly impact the economic performance of the

Maritime Link. Thus, Emera began recording the

Maritime Link as an equity investment.

BLPC has established a Self-Insurance Fund (“SIF”), primarily

for the purpose of building a fund to cover

risk against damage and consequential loss to certain

generating, transmission and distribution

systems. ECI holds a variable interest in the SIF for which

it was determined that ECI was the primary

beneficiary and, accordingly,

the SIF must be consolidated by ECI. In its determination that

ECI controls

the SIF,

management considered that, in substance, the activities

of the SIF are being conducted on

behalf of ECI’s subsidiary BLPC and BLPC, alone,

obtains the benefits from the SIF’s

operations. Additionally,

because ECI, through BLPC, has rights to all

the benefits of the SIF,

it is also

exposed to the risks related to the activities of the SIF.

Any withdrawal of SIF fund assets by the

Company would be subject to existing regulations. Emera’s

consolidated VIE in the SIF is recorded as

“Other long-term assets”, “Restricted cash” and “Regulatory liabilities”

on the Consolidated Balance

Sheets. Amounts included in restricted cash represent

the cash portion of funds required to be set aside

for the BLPC SIF.

The Company has identified certain long-term purchase power

agreements that meet the definition of

variable interests as the Company has to purchase all

or a majority of the electricity generation at a fixed

price. However, it was determined

that the Company was not the primary beneficiary

since it lacked the

power to direct the activities of the entity,

including the ability to operate the generating facilities

and make

management decisions.

The following table provides information about Emera’s

portion of material unconsolidated VIEs:

As at

December 31, 2021

December 31, 2020

Maximum

millions of Canadian dollars

Total

assets

exposure to

loss

Total

assets

exposure to

loss

Unconsolidated VIEs in which Emera has variable interests

NSPML (equity accounted)

533

547

33.

SUBSEQUENT EVENTS

These financial statements and notes reflect the Company’s

evaluation of events occurring subsequent to

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

the financial statements were issued.

EX-99.4

Exhibit 99.4

Consent of Independent Registered Public Accounting Firm

We consent to the reference to our Firm under the caption “Experts” in the Annual Information Form and to the use in this Annual Report on Form 40-F of our report dated February 14, 2022, with respect to the consolidated balance sheets of Emera Incorporated as at December 31, 2021 and 2020, and the consolidated statements of income, consolidated statements of comprehensive income, consolidated statements of changes in equity and consolidated statements of cash flows for the years then ended, included in this Annual Report on Form 40-F.

	/s/ Ernst & Young LLP
Halifax, Canada	Chartered Professional Accountants
February 14, 2022

EX-99.5

Exhibit 99.5

CERTIFICATION

I, Scott C. Balfour, certify that:

1.	I have reviewed this annual report on Form 40-F of Emera Incorporated;<br>
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a<br>material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
---	---
3.	Based on my knowledge, the financial statements, and other financial information included in this report,<br>fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
---	---
4.	The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure<br>controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:
---	---
a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be<br>designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being<br>prepared;
---	---
b)	Designed such internal control over financial reporting, or caused such internal control over financial<br>reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting<br>principles;
---	---
c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this<br>report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
---	---
d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that<br>occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and
---	---
5.	The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of<br>internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):
---	---
a)	All significant deficiencies and material weaknesses in the design or operation of internal control over<br>financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
---	---
b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in<br>the issuer’s internal control over financial reporting.
---	---
Date: February 14, 2022
---
/s/ Scott C. Balfour
Scott C. Balfour
President & Chief Executive Officer

EX-99.6

Exhibit 99.6

CERTIFICATION

I, Gregory W. Blunden, certify that:

1.	I have reviewed this annual report on Form 40-F of Emera Incorporated;<br>
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a<br>material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
---	---
3.	Based on my knowledge, the financial statements, and other financial information included in this report,<br>fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
---	---
4.	The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure<br>controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:
---	---
a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be<br>designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being<br>prepared;
---	---
b)	Designed such internal control over financial reporting, or caused such internal control over financial<br>reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting<br>principles;
---	---
c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this<br>report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
---	---
d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that<br>occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and
---	---
5.	The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of<br>internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):
---	---
a)	All significant deficiencies and material weaknesses in the design or operation of internal control over<br>financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
---	---
b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in<br>the issuer’s internal control over financial reporting.
---	---
Date: February 14, 2022
---
/s/ Gregory W. Blunden
Gregory W. Blunden
Chief Financial Officer

EX-99.7

Exhibit 99.7

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ENACTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Emera Incorporated (the “Company”) on Form 40-F for the year ended December 31, 2021 (the “Report”) as filed with the U.S. Securities and Exchange Commission,

I, Scott C. Balfour, President & Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as enacted pursuant to Section 906 of the U.S. Sarbanes-Oxley Act of 2002, that to my knowledge:

(i)	the Report fully complies with the requirements of Section 13(a) or 15(d) of the U.S. Securities Exchange<br>Act of 1934; and
(ii)	the information contained in the Report fairly presents, in all material respects, the financial condition and<br>results of operations of the Company.
---	---
Date: February 14, 2022
---
/s/ Scott C. Balfour
Scott C. Balfour
President & Chief Executive Officer

EX-99.8

Exhibit 99.8

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ENACTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Gregory W. Blunden, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as enacted pursuant to Section 906 of the U.S. Sarbanes-Oxley Act of 2002, that to my knowledge:

(i)	the Report fully complies with the requirements of Section 13(a) or 15(d) of the U.S. Securities Exchange<br>Act of 1934; and
(ii)	the information contained in the Report fairly presents, in all material respects, the financial condition and<br>results of operations of the Company.
---	---
Date: February 14, 2022
---
/s/ Gregory W. Blunden
Gregory W. Blunden
Chief Financial Officer