# EDGAR Filing Document

**Accession Number:** 0001127248
**File Stem:** 0001193125-23-048555
**Filing Date:** 2023-2
**Character Count:** 688803
**Document Hash:** 7df01f95e7cae31c4722cc350259596b
**Contains OCR:** False
**Source Format:** 

## Filing Content

## Filing Summary
**0001193125-23-048555.hdr.sgml**: 20230224

**ACCESSION NUMBER**: 0001193125-23-048555

**CONFORMED SUBMISSION TYPE**: 40-F

**PUBLIC DOCUMENT COUNT**: 193

**CONFORMED PERIOD OF REPORT**: 20221231

**FILED AS OF DATE**: 20230224

**DATE AS OF CHANGE**: 20230224

**FILER**: 

**COMPANY DATA:**
- **COMPANY CONFORMED NAME:** EMERA INC
- **CENTRAL INDEX KEY:** 0001127248
- **STANDARD INDUSTRIAL CLASSIFICATION:** ELECTRIC SERVICES [4911]
- **IRS NUMBER:** 868143132
- **FISCAL YEAR END:** 1231

**FILING VALUES:**
- **FORM TYPE:** 40-F
- **SEC ACT:** 1934 Act
- **SEC FILE NUMBER:** 000-54516
- **FILM NUMBER:** 23666051

**BUSINESS ADDRESS:**
- **STREET 1:** 1223 LOWER WATER ST., B-6TH FLOOR
- **STREET 2:** P.O. BOX 910
- **CITY:** HALIFAX
- **STATE:** A5
- **ZIP:** B3J 3S8
- **BUSINESS PHONE:** 902-428-6494

**MAIL ADDRESS:**
- **STREET 1:** 1223 LOWER WATER ST., B-6TH FLOOR
- **STREET 2:** P.O. BOX 910
- **CITY:** HALIFAX
- **STATE:** A5
- **ZIP:** B3J 3S8

?xml version="1.0" encoding="utf-8" ? 40-F

#### UNITED STATES

#### SECURITIES AND EXCHANGE COMMISSION

#### Washington, D.C. 20549

#### FORM

#### 40-F
☐

REGISTRATION STATEMENT 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, 2022

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, 2022:

269,944,308

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

☐

No

☒

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

☒

No

☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the

registrant included in the filing reflect the correction of an error to previously issued financial statements.

☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-

based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to

§ 240.10D-1(b).

☐

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 to use the extended transition period for complying with any new or 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 by check mark whether the registrant has filed a report on and attestation to its management's assessment of 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, 2022, 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 the United States

Securities and Exchange Commission's (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,

2022 and concluded that the Registrant's internal control over financial reporting is effective as at

December 31, 2022.

(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, 2022, 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 six

audit committee financial experts serve on its Audit Committee. The audit committee financial experts are Paula Y.

Gold-Williams, Kent M. Harvey, B. Lynn Loewen, Ian E. Robertson, Andrea S. Rosen and Richard P. Sergel. The

Board has determined that Paula Y. Gold-Williams, Kent M. Harvey, B. Lynn Loewen, Ian E. Robertson, 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 Paula Y. Gold-Williams, Kent M. Harvey, B. Lynn

Loewen, Ian E. Robertson, 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, 2022, 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 October 1, 2022 (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 November 16, 2022 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 2022 and none were approved pursuant to the de minimis

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

In connection with the 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 23, 2023 for the

year ended December 31, 2022, 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, 2022 and December 31, 2021, 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 [2022 Annual Information Form dated February 23, 2023 for the fiscal year ended December 31,](d417839dex991.htm)

[2022](d417839dex991.htm)

99.2 [Management's Discussion and Analysis dated February 23, 2023 for the year ended December](d417839dex992.htm)

[31, 2022](d417839dex992.htm)

99.3 [Audited Consolidated Financial Statements as at and for the years ended December 31, 2022 and](d417839dex993.htm)

[December 31, 2021](d417839dex993.htm)

99.4 [Consent of Independent Registered Public Accounting Firm](d417839dex994.htm)

99.5 [Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the U.S.](d417839dex995.htm)

[Securities Exchange Act of 1934, as amended](d417839dex995.htm)

99.6 [Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the U.S.](d417839dex996.htm)

[Securities Exchange Act of 1934, as amended](d417839dex996.htm)

99.7 [Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of](d417839dex997.htm)

[2002](d417839dex997.htm)

99.8 [Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of](d417839dex998.htm)

[2002](d417839dex998.htm)

99.9 [Emera Code of Conduct (as revised on October 1, 2022) (incorporated by reference to Emera](https://www.sec.gov/Archives/edgar/data/1127248/000119312522286213/d439442dex991.htm)

[Incorporated's Form 6-K, furnished to the Commission on November 16, 2022)](https://www.sec.gov/Archives/edgar/data/1127248/000119312522286213/d439442dex991.htm)

Interactive Data File (formatted as Inline XBRL)

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 24

th

day of February, 2023.

#### EMERA

#### INCORPORATED
By: /s/ Scott C. Balfour

Name: Scott C. Balfour

Title: President & Chief

Executive Officer

## Exhibit 99.1

**Exhibit 99.1**![LOGO](g417839g0222224838065.jpg)

**Emera Incorporated** 

**Annual Information Form** 

For the year ended December 31, 2022

**February 23, 2023** 

------

**ANNUAL INFORMATION FORM** 

For the year ended December 31, 2022

Dated: February 23, 2023

**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** |  |
|  **DESCRIPTION OF THE BUSINESS** |  | **8** |  |
|  ***Business Segments*** | **** | ***8*** | **** |
|  ***Florida Electric Utility*** | **** | ***9*** | **** |
|  ***Canadian Electric Utilities*** | **** | ***11*** | **** |
|  ***Gas Utilities and Infrastructure*** | **** | ***14*** | **** |
|  ***Other Electric Utilities*** | **** | ***17*** | **** |
|  ***Other*** | **** | ***18*** | **** |
|  **GENERAL DEVELOPMENT OF THE BUSINESS** |  | **19** |  |
|  ***Florida Electric Utility*** | **** | ***19*** | **** |
|  ***Canadian Electric Utilities*** | **** | ***21*** | **** |
|  ***Gas Utilities and Infrastructure*** | **** | ***24*** | **** |
|  ***Other Electric Utilities*** | **** | ***25*** | **** |
|  ***USGAAP – Exemptive Relief*** | **** | ***27*** | **** |
|  ***Financing Activity*** | **** | ***27*** | **** |
|  **RISK FACTORS** |  | **28** |  |
|  **CAPITAL STRUCTURE** |  | **28** |  |
|  ***Common Shares*** | **** | ***29*** | **** |
|  ***Emera First Preferred Shares*** | **** | ***29*** | **** |
|  ***Emera Second Preferred Shares*** | **** | ***29*** | **** |
|  ***Share Ownership Restrictions*** | **** | ***29*** | **** |
|  **CREDIT RATINGS** |  | **30** |  |
|  **DIVIDENDS** |  | **31** |  |
|  **MARKET FOR SECURITIES** |  | **32** |  |
|  ***Trading Price and Volume*** | **** | ***32*** | **** |
|  ***At-The-Market Equity Program*** | **** | ***32*** | **** |
|  **DIRECTORS AND OFFICERS** |  | **33** |  |
|  ***Directors*** | **** | ***33*** | **** |
|  ***Officers*** | **** | ***35*** | **** |
| **AUDIT COMMITTEE** |  | **36** |  |
|  ***Audit and Non-Audit Services Pre-Approval Process*** | **** | ***37*** | **** |

---

*Emera Incorporated – 2022 Annual Information Form* *2*

------

---

| | | |
|:---|:---|:---|
| ***Auditors' Fees*** | **** | ***38*** |
| **CERTAIN PROCEEDINGS** |  | **38** |
| **CONFLICTS OF INTEREST** |  | **39** |
| **LEGAL PROCEEDINGS AND REGULATORY ACTIONS** |  | **39** |
| **NO INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS** |  | **39** |
| **MATERIAL CONTRACTS** |  | **39** |
| **TRANSFER AGENT AND REGISTRAR** |  | **39** |
| **EXPERTS** |  | **39** |
| **ADDITIONAL INFORMATION** |  | **39** |
| **APPENDIX "A" - DEFINITIONS OF CERTAIN TERMS** |  | **41** |
| **APPENDIX "B" – SUMMARY OF TERMS AND CONDITIONS OF AUTHORIZED SERIES OF FIRST PREFERRED SHARES** |  | **46** |
| **APPENDIX "C" - MONTHLY TRADING VOLUME AND HIGH AND LOW PRICE FOR EMERA'S SECURITIES IN 2022** |  | **49** |
| **APPENDIX "D" - EMERA INCORPORATED AUDIT COMMITTEE CHARTER** |  | **50** |

---

*Emera Incorporated – 2022 Annual Information Form* *3*

------

**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, 2022. 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 and Ratios", which is incorporated herein by reference, a copy of which is available electronically under Emera's profile on SEDAR at <u>www.sedar.com</u>.

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 <u>www.sedar.com</u>.

**CAUTIONARY NOTE REGARDING FORWARD-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

*Emera Incorporated – 2022 Annual Information Form* *4*

------

fluctuations; expected changes in electricity rates; and the impacts of planned investment by the industry of gas transportation infrastructure within the United States.

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 and political risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; liquidity and capital market risk; future dividend growth; timing and costs associated with certain capital investments; expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; maintenance of adequate insurance coverage; changes in customer energy usage patterns; developments in technology that could reduce demand for electricity; global climate change; weather; unanticipated maintenance and other expenditures; system operating and maintenance risk; derivative financial instruments and hedging; interest rate risk; inflation risk; counterparty risk; disruption of fuel supply; country risks; environmental risks; foreign exchange ("FX"); regulatory and government decisions, including changes to environmental, financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of service area; risk of failure of information technology 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 – 2022 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. These legislative amendments did not alter the existing 15 per cent individual share ownership restriction, as described below in the section entitled "Capital Structure – Share Ownership Restrictions". The Board approved amendments to the Company's Articles and on July 11, 2019, shareholders passed a special resolution to amend the Articles to remove this non-Canadian resident ownership 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 <u>www.sedar.com</u>.

***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, 2022.

---

| | | |
|:---|:---|:---|
| **Subsidiaries** | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Percentage Ownership** <br> **(%)** | **Jurisdiction** |
| &nbsp;&nbsp; **Tampa Electric Company<sup>1</sup>** | 100 | Florida |
| &nbsp;&nbsp; **Nova Scotia Power** | 100 | Nova Scotia |
| &nbsp;&nbsp; **New Mexico Gas Company** | 100 | Delaware |

---

&nbsp;&nbsp;&nbsp;&nbsp;(1) Tampa Electric Company (TEC) has historically included both its regulated electric and gas utilities, namely the Tampa
Electric Division and the Peoples Gas System (PGS) Division. Effective January 1, 2023, PGS ceased to be a division of TEC and the gas utility was reorganized, resulting in a separate legal entity called Peoples Gas System, Inc. (PGSI),
existing under the laws of the State of Florida, and a wholly-owned direct subsidiary of TECO Gas Operations, Inc.

*Emera Incorporated – 2022 Annual Information Form* *6*

------

**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.

The majority of Emera's investment in rate-regulated businesses are located in Florida with other investments in Nova Scotia, New Mexico and the Caribbean. Emera's portfolio of regulated utilities provides reliable earnings, cash flow and dividends. Earnings opportunities in regulated utilities are generally driven by the magnitude of net investment in the utility (known as "rate base"), and the amount of equity in the capital structure and the ROE as approved through regulation. Earnings are also affected by sales volumes and operating expenses.

Emera's capital investment plan is $8-9 billion over the 2023-to-2025 period (including a $240 million equity investment in the LIL in 2023), mainly focused in Florida. This results in a forecasted rate base growth of approximately 7 per cent to 8 per cent through 2025. The capital investment plan continues to include significant investments across the portfolio in renewable and cleaner generation, reliability and integrity investments, infrastructure modernization and customer-focused technologies. Emera's capital investment plan is being funded primarily through internally generated cash flows and debt raised at the operating company level. Equity requirements in support of the Company's capital investment plan are expected to be funded through the issuance of preferred equity and the issuance of common equity through Emera's DRIP and ATM Program. Maintaining investment-grade credit ratings is a priority of the Company.

Emera has provided annual dividend growth guidance of four to five per cent through 2025. The Company targets a long-term dividend payout ratio of adjusted net income of 70 to 75 per cent and, while the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to return to that range over time. For further information on the non-GAAP measure "Dividend Payout Ratio of Adjusted Net Income", refer to the "Non-GAAP Financial Measures and Ratios" section of the MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera's profile on SEDAR at <u>www.sedar.com</u>.

Seasonal patterns and other weather events affect demand and operating costs. Similarly, mark-to-market adjustments and foreign currency exchange can have a material impact on financial results for a specific period. Emera's consolidated net income and cash flows are impacted by movements in the USD relative to the Canadian dollar. Emera may hedge both transactional and translational exposure. These impacts, as well as the timing of capital investments and other factors, mean results in any one quarter are not necessarily indicative of results in any other quarter, or for the year as a whole.

Energy markets worldwide are facing significant change and Emera is well positioned to respond to shifting customer demands, digitization, decarbonization, complex regulatory environments and decentralized generation.

Customers are looking for more choice, better control, and enhanced reliability in a time where costs of decentralized generation and storage have become more competitive in some regions. Advancing technologies are transforming the way utilities interact with their customers and generate and transmit energy. In addition, climate change and extreme weather are shaping how utilities operate and how they invest in infrastructure. There is also an overall need to replace aging infrastructure and further enhance reliability. Emera will play a role in all of these trends. Emera's strategy is to fund investments in renewable energy and technology assets which protect the environment and benefit customers through fuel or operating cost savings.

For example, significant investments to facilitate the use of renewable and low-carbon energy include the Maritime Link in Atlantic Canada, modernization of the Big Bend Power Station and the ongoing construction of solar generation at Tampa Electric. Emera's utilities are also investing in reliability projects

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and replacing aging infrastructure. All of these projects demonstrate Emera's strategy of safely delivering cleaner, reliable, and affordable energy for its customers.

Building on its decarbonization progress, Emera is continuing its efforts by establishing clear carbon reduction goals and a vision to achieve net-zero carbon dioxide emissions by 2050.

This vision is inspired by Emera's strong track record, the Company's experienced team, and a clear path to Emera's interim carbon goals. With existing technologies and resources, and subject to supportive government and regulatory decisions, Emera is working to achieve the following goals compared to corresponding 2005 levels:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;· A 55 per cent reduction in carbon dioxide emissions by 2025.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;· The retirement of Emera's last existing coal unit no later than 2040.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;· An 80 per cent reduction in carbon dioxide emissions by 2040.

Achieving the above climate goals on these timelines is subject to the Company's regulatory obligations and other external factors beyond Emera's control.

Emera seeks to deliver on its Climate Commitment while maintaining its focus on investing in reliability and staying focused on the cost impacts for customers. Emera is also committed to identifying emerging technologies and continuing to work constructively with policymakers, regulators, partners, investors and customers to achieve these goals and realize its net-zero vision.

Emera is committed to world-class safety, operational excellence, good governance, excellent customer service, reliability, being an employer of choice, and building constructive relationships.

**DESCRIPTION OF THE BUSINESS** 

***Business Segments***

Emera's reportable segments are:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;· **Florida Electric Utility**, which consists of Tampa Electric;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;· **Canadian Electric Utilities**, which includes NSPI and ENL, a holding company with equity investments in NSPML (100
per cent) and the LIL (31.9 per cent);

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;· **Gas Utilities and Infrastructure**, which includes PGS, NMGC, Emera Brunswick Pipeline Company, SeaCoast and an
12.9 per cent equity investment in M&NP;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;· **Other Electric Utilities**, which includes ECI, a holding company with regulated electric utilities which include
BLPC, GBPC and a 19.5 per cent equity interest in Lucelec. On March 31 2022, Emera completed the sale of its 51.9 per cent interest in Domlec, which was previously included in this segment; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;· **Other**, which includes Emera Energy, ETL and corporate holding, financing companies and certain other
investments.

***General***

Emera and its subsidiaries had 7,122 employees as at December 31, 2022, approximately 32 per cent of whom are unionized.

***Operations by Segment***

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

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***Florida Electric Utility***

Florida Electric Utility consists of Tampa Electric, a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity, serving customers in West Central Florida. Tampa Electric has $12.1 billion USD of assets, approximately 827,000 customers and 2,469 employees as at December 31, 2022.

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. Tampa Electric's approved regulated ROE range is 9.25 per cent to 11.25 per cent, based on an allowed equity capital structure of 54 per cent. An ROE of 10.20 per cent will be used for the calculation of the return on investments for clauses.

For further details on Tampa Electric's regulatory environment, base rates and recovery mechanisms, refer to Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which are hereby incorporated by reference, a copy of which is available electronically under Emera's profile on SEDAR at <u>www.sedar.com</u>.

**Market and Sales** 

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| | | | | |
|:---|:---|:---|:---|:---|
| &nbsp;&nbsp;&nbsp;**Tampa Electric Revenue and Sales Volumes by Customer Class** | &nbsp;&nbsp;&nbsp;**Tampa Electric Revenue and Sales Volumes by Customer Class** | &nbsp;&nbsp;&nbsp;**Tampa Electric Revenue and Sales Volumes by Customer Class** | &nbsp;&nbsp;&nbsp;**Tampa Electric Revenue and Sales Volumes by Customer Class** | &nbsp;&nbsp;&nbsp;**Tampa Electric Revenue and Sales Volumes by Customer Class** |
|  | **Electric Revenues (%)** | **Electric Revenues (%)** | **GWh Electric Sales Volumes (%)** | **GWh Electric Sales Volumes (%)** |
| &nbsp;&nbsp;&nbsp;**For the year ended December 31** | **2022** | **2021** | **2022** | **2021** |
| &nbsp;&nbsp;&nbsp; Residential | 54.7 | 53.2 | 48.4 | 49.2 |
| &nbsp;&nbsp;&nbsp; Commercial | 26.4 | 27.7 | 30.2 | 30.4 |
| &nbsp;&nbsp;&nbsp; Industrial | 7.0 | 7.9 | 10.1 | 10.5 |
| &nbsp;&nbsp;&nbsp; Other | 11.9 | 11.2 | 11.3 | 9.9 |
| &nbsp;&nbsp;&nbsp; **Total** | **100.0** | **100.0** | **100.0** | **100.0** |

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**Energy sources and generation** 

As at December 31, 2022, Tampa Electric owns 6,549 MW of generating capacity, of which 78 per cent is natural gas-fired, 15 per cent is solar and 7 per cent is coal. Tampa Electric owns 2,171 kilometres of transmission facilities and 19,916 kilometres of distribution facilities. Tampa Electric meets the planning criteria for reserve capacity established by the FPSC, which is a 20 per cent reserve margin over firm peak demand.

**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.

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**Contribution to Consolidated Net Income** 

Florida Electric Utility's contribution to consolidated net income was $458 million USD in 2022 (2021 - $369 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 2022, capital investments (including AFUDC) in the Florida Electric Utility segment were $1.1 billion USD (2021 – $1.2 billion USD). In 2023, capital investment is expected to be approximately $1.3 billion USD, including AFUDC. Capital projects include solar investments, grid modernization and storm hardening investments.

**Environmental Considerations** 

Tampa Electric has significant environmental considerations. 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 on all applicable units 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). As a result of legal challenges, a replacement rule is expected to be proposed in April 2023. Compliance with the terms of the new rule that replaces the ACE 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 CO<sub>2</sub> 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.

*Emera Incorporated – 2022 Annual Information Form* *10*

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*Water Supply 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. Polk Power Station is not covered by this rule since it does not operate an intake on waters of the U.S. Tampa Electric has two ongoing projects (one for Bayside and one for Big Bend) that require compliance with the rule. The Florida Department of Environmental Protection (FDEP) agreed with Tampa Electric's proposed plan for Bayside and Tampa Electric began a multi-year construction project to install new fish-friendly modified traveling screens and a fish return in 2022. Compliance study elements have been completed and submitted for Bayside. Tampa Electric is negotiating an alternative schedule for a portion of the compliance requirements with the Big Bend modernization project, with the remainder of the compliance requirements to be determined and completed at a later date. The full impact of the regulations on Tampa Electric will depend on the outcome of subsequent legal proceedings challenging the rule, the results of the study elements performed as part of the rules' implementation, and the actual requirements established by FDEP.

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. The EPA has announced that this rule is currently under review, and a revised rule is expected to be proposed in 2023.

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. Big Bend will complete construction of a deep injection well system in December 2023 for disposal of various wastewaters. 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 31.9 per cent equity investment in LIL: two transmission investments related to the development of an 824 MW hydroelectric generating facility at Muskrat Falls hydroelectric project ("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 541,000 customers with $6.8 billion in assets and 2,138 employees as at December 31, 2022.

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. On January 27, 2022, NSPI filed a General Rate Application ("GRA") with the UARB. For more details regarding GRA, refer to the General Development of the Business section below, under the heading "Canadian Electric Utilities – NSPI - General Rate Application."

For further details on NSPI's regulatory environment and recovery mechanisms, refer to Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which are hereby incorporated by reference, a copy of which is available electronically under Emera's profile on SEDAR at <u>www.sedar.com</u>.

*Emera Incorporated – 2022 Annual Information Form* *11*

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**Market and Sales** 

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| | | | | |
|:---|:---|:---|:---|:---|
| &nbsp;&nbsp;&nbsp;**NSPI Revenue and Electricity Sales Volumes by Customer Class** | &nbsp;&nbsp;&nbsp;**NSPI Revenue and Electricity Sales Volumes by Customer Class** | &nbsp;&nbsp;&nbsp;**NSPI Revenue and Electricity Sales Volumes by Customer Class** | &nbsp;&nbsp;&nbsp;**NSPI Revenue and Electricity Sales Volumes by Customer Class** | &nbsp;&nbsp;&nbsp;**NSPI Revenue and Electricity Sales Volumes by Customer Class** |
|  | **Electric Revenues (%)** | **Electric Revenues (%)** | **GWh Electric Sales Volumes (%)** | **GWh Electric Sales Volumes (%)** |
| &nbsp;&nbsp;&nbsp;**For the year ended December 31** | **2022** | **2021** | **2022** | **2021** |
| &nbsp;&nbsp;&nbsp;Residential | 50.8 | 54.3 | 46.1 | 45.7 |
| &nbsp;&nbsp;&nbsp;Commercial | 26.0 | 27.7 | 28.8 | 28.5 |
| &nbsp;&nbsp;&nbsp;Industrial | 21.5 | 16.2 | 23.7 | 24.3 |
| &nbsp;&nbsp;&nbsp;Other | 1.7 | 1.8 | 1.4 | 1.5 |
| &nbsp;&nbsp;&nbsp;**Total** | **100.0** | **100.0** | **100.0** | **100.0** |

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**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 petcoke and 2 per cent is biomass-fueled generation. In addition, NSPI has contracts to purchase renewable energy from IPPs, including COMFIT participants, which own 546 MW of capacity. NSPI also has rights to 153 MW of Maritime Link capacity, representing Nalcor's NS Block delivery obligations, as discussed below.

**System Operations** 

NSPI's Control Center Operations co-ordinates and controls the electric generation, transmission and distribution facilities with the goal of providing safe, reliable and efficient electricity supply while adhering to applicable environmental requirements and regulations. 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 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, transmission line capacity 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's final commissioning of the LIL has experienced delays and it's expected that final commissioning of the LIL will be completed in 2023. Nalcor's NS Block delivery obligations commenced on August 15, 2021 and the NS Block will be delivered over the next 35 years pursuant to the project agreements. During these final stages of commissioning the LIL, there will be interruptions in supply, with any resultant delivery shortfalls being delivered on a timely basis in accordance

*Emera Incorporated – 2022 Annual Information Form* *12*

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with the Energy and Capacity Agreement. NSPI has the option of purchasing additional market-priced energy from Nalcor through the Energy Access Agreement. The Energy Access Agreement enables NSPI to access a market-priced bid from Nalcor for up to 1.8 Terawatt hours ("TWh") of energy in any given year and, on average, 1.2 TWh of energy per year through August 31, 2041.

*LIL* 

ENL is a limited partner with Nalcor in LIL. Construction of the LIL is complete and Nalcor is forecasting it will achieve final commissioning in 2023.

Equity earnings from the LIL investment are based upon the book value of the equity investment and the approved ROE. Emera's current equity investment is $740 million, comprised of $410 million in equity contribution and $330 million of accumulated equity earnings. Emera's total equity contribution in the LIL, excluding accumulated equity earnings, is estimated to be approximately $650 million after 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 2023, and until that point Emera will continue to record AFUDC earnings.

**Contribution to Consolidated Net Income and Adjusted Net Income** 

Canadian Electric Utilities contribution to consolidated net income was $215 million in 2022 (2021 - $241 million). Canadian Electric Utilities contribution to Emera's consolidated adjusted net income was $222 million in 2022 (2021 - $241 million). For a reconciliation of Canadian Electric Utilities adjusted net income to consolidated net income, refer to the "Non-GAAP Financial Measures and Ratios" and "Financial Highlights – Canadian 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 <u>www.sedar.com</u>

**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 Q1 historically generating the highest sales, reflecting colder weather and fewer daylight hours in the winter season.

**Capital Investment** 

*NSPI* 

NSPI's capital investments in 2022 were $540 million (2021 - $388 million), including AFUDC. In 2023, NSPI expects to invest $375 million, including AFUDC, primarily in capital projects to support system reliability and reliable service for customers.

*NSPML* 

NSPML's capital investments in 2022 were $10 million (2021 – $6 million). NSPML does not anticipate any planned significant capital investment in 2023.

**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. NSPI faces risks associated with achieving climate-related and environmental legislative requirements, including the risk of non-compliance, which could adversely affect NSPI's

*Emera Incorporated – 2022 Annual Information Form* *13*

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operations and financial performance. For further discussion on these risks and environmental legislation and regulations, refer to the "Enterprise Risk and Risk Management" 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. Recent developments related to provincial and federal environmental laws and regulations are referred to below in the "General Developments of the Business" section.

*Nova Scotia Cap-and-Trade Program Regulations* 

NSPI is a participant in the Nova Scotia Cap-and-Trade Program ("Cap-and-Trade Program") and is subject to the 2019 through 2022 compliance period. NSPI received granted emissions allowances under the Cap-and-Trade Program and is permitted to purchase up to five per cent of the credits available at provincial auctions. Any remaining allowance shortfall requires the purchase of reserve credits directly from the provincial government, which are anticipated to be priced at a premium to provincial auction pricing. Compliance is forecast to be achieved through granted emissions allowances and credit purchases under the Cap-and-Trade Program, including reserve credits. Lower than forecast Muskrat Falls energy received during the compliance period has resulted in the increased deployment of higher carbon-emitting generation sources. The Province of Nova Scotia has agreed to provide approximately $165 million of relief from the 2019 through 2022 compliance costs, which was equal to the total cost of compliance forecast at the time of the fuel update submitted by NSPI to the UARB in September 2022 as part of the GRA. Discussions related to the final amount of relief and how this relief will be provided are ongoing. Further, NSPI's regulatory framework provides for the recovery of costs prudently incurred to comply with the Cap-and-Trade Program Regulations pursuant to NSPI's FAM.

*Nova Scotia Renewable Energy Regulations* 

Over the past several years, the requirement to reduce Nova Scotia's reliance upon higher carbon and greenhouse gas 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.

Under the provincially legislated Renewable Energy Regulations, 40 per cent of electric sales must be generated from renewable sources. This standard was predicated on receipt of the full NS Block. Due to the delay of the NS Block, the provincial government provided NSPI with an alternative compliance plan that requires NSPI to achieve 40 per cent of electric sales generated from renewable sources over the 2020 through 2022 period. With delivery of the NS Block commencing later than anticipated, as well as further interruptions in supply due to delays in the LIL, NSPI did not achieve the requirements of the alternative compliance plan. The Renewable Energy Regulations require NSPI to have acted in a duly diligent manner. If NSPI is found not to have acted in a duly diligent manner, it could be subject to a maximum penalty of $10 million.

*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 2022 Annual Information Form, a copy of which is available electronically under NSPI's profile on SEDAR at <u>www.sedar.com</u>.

***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

*Emera Incorporated – 2022 Annual Information Form* *14*

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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 on which NMGC has transportation capacity and NMGC's intrastate transmission and distribution system for delivery to customers.

**Market and sales** 

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| | | | | |
|:---|:---|:---|:---|:---|
| &nbsp;&nbsp;&nbsp;**PGS, NMGC and SeaCoast Revenue and Sales Volumes by Customer Class** | &nbsp;&nbsp;&nbsp;**PGS, NMGC and SeaCoast Revenue and Sales Volumes by Customer Class** | &nbsp;&nbsp;&nbsp;**PGS, NMGC and SeaCoast Revenue and Sales Volumes by Customer Class** | &nbsp;&nbsp;&nbsp;**PGS, NMGC and SeaCoast Revenue and Sales Volumes by Customer Class** | &nbsp;&nbsp;&nbsp;**PGS, NMGC and SeaCoast Revenue and Sales Volumes by Customer Class** |
|  | **Gas Revenues (%)** | **Gas Revenues (%)** | **Therms Gas Sales Volumes (%)** | **Therms Gas Sales Volumes (%)** |
| &nbsp;&nbsp;&nbsp;**For the year ended December 31** | **2022** | **2021** | **2022** | **2021** |
| &nbsp;&nbsp;&nbsp;Residential | 49.2 | 53.1 | 14.4 | 14.6 |
| &nbsp;&nbsp;&nbsp;Commercial | 28.3 | 31.4 | 28.7 | 28.8 |
| &nbsp;&nbsp;&nbsp;Industrial | 5.1 | 5.5 | 49.1 | 51.7 |
| &nbsp;&nbsp;&nbsp;Other | 17.4 | 10.0 | 7.8 | 4.9 |
| &nbsp;&nbsp;&nbsp;**Total** | **100.0** | **100.0** | **100.0** | **100.0** |

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**PGS** 

As at December 31, 2022, PGS serves approximately 468,000 customers with $2.5 billion USD in assets and 767 employees. The PGS system includes approximately 24,300 kilometres of natural gas mains and 13,500 kilometres of service lines. Natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) was 2 billion therms in 2022.

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 or revenue requirements equal to their cost to provide service, plus an appropriate return on invested capital. As of 2022, the approved ROE range for PGS is 8.9 per cent to 11.0 per cent, based on an allowed equity capital structure of 54.7 per cent. An ROE of 9.9 per cent is used for the calculation of return on investments recovered through cost recovery clauses.

For further details on PGS' regulatory environment and recovery mechanisms, refer to Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which are hereby incorporated by reference, a copy of which is available electronically under Emera's profile on SEDAR at <u>www.sedar.com</u>.

**NMGC** 

As at December 31, 2022, NMGC serves approximately 545,000 customers with $2.0 billion USD in assets and 678 employees. NMGC's system includes 2,426 km of transmission lines and 17,781 km of distribution lines. Annual natural gas throughput was 926 million therms in 2022.

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. As of 2022, the approved ROE for NMGC is 9.375 per cent on an allowed equity capital structure of 52 per cent. For further details on NMGC's regulatory environment and recovery mechanisms, refer to Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which are hereby incorporated by reference, a copy of which is available electronically under Emera's profile on SEDAR at <u>www.sedar.com</u>.

**EBPC** 

EBPC owns Brunswick Pipeline, a regulated 145-km pipeline delivering re-gasified liquefied natural gas from the Saint John LNG import terminal near Saint John, New Brunswick to markets in the Northeastern

*Emera Incorporated – 2022 Annual Information Form* *15*

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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 RENAC 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 RENAC, as noted above. The firm service agreement provides for a predetermined toll increase in the fifth and fifteenth year of the contract.

**SeaCoast** 

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 in Putnam County, Florida. SeaCoast operates a 21-mile, 30-inch pipeline lateral that is treated as a sales-type lease for accounting purposes. The lease of the pipeline lateral to Seminole commenced on January 1, 2022.

**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 $170 million USD in 2022 (2021 – $157 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 2022 were $436 million USD (2021 - $407 million USD). In 2023, capital investment is expected to be approximately $475 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.

**Economic Dependence** 

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

*Emera Incorporated – 2022 Annual Information Form* *16*

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***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 and a 19.5 per cent interest in Lucelec on the island of St. Lucia which is accounted for on the equity basis.

On March 31, 2022, Emera completed the sale of Domlec. For further details, refer to refer to Note 4, Dispositions, in the Audited Financial Statements, which is, incorporated herein by reference, a copy of which is available electronically under Emera's profile on SEDAR at <u>www.emera.com</u>

**Market and Sales** 

Other Electric Utilities operating revenues for 2022 were $398 million USD (2020 – $355 million USD) and electric sales volumes were 1,239 GWh (2021 –1,262 GWh).

***BLPC***

As at December 31, 2022, BLPC serves approximately 133,000 customers with $505 million USD of assets and a workforce of 402 employees. BLPC owns 276 MW of generating capacity, of which 96 per cent is oil-fired and 4 per cent is solar. 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 3,789 km of distribution lines which includes distribution supply substations.

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. For more details regarding the new licenses, refer to the General Development of the Business section below, under the heading "BLPC License Negotiations".

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 approved regulated return on rate base was 10 per cent for 2022 and 2021. For further details on BLPC's regulatory environment and recovery mechanisms, refer to Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera's profile on SEDAR at <u>www.sedar.com</u>.

***GBPC***

As at December 31, 2022, GBPC serves approximately 19,000 customers, with $338 million USD of assets and a workforce of 201 employees. GBPC owns 98 MW of oil-fired generation, approximately 90 kilometres of transmission facilities and 670 kilometers of distribution facilities.

GBPC is regulated by the GBPA. Rates are set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on rate base. For further details on GBPC's regulatory environment and recovery mechanisms, refer to Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera's profile on SEDAR at <u>www.sedar.com</u>.

**System Operation** 

BLPC and GBPC 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

*Emera Incorporated – 2022 Annual Information Form* *17*

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

**Contribution to Consolidated Net Income and Adjusted Net Income** 

Other Electric Utilities' contribution to consolidated net income was a loss of $35 million USD in 2022 (2021 – income of $17 million USD). Other Electric Utilities' contribution to consolidated adjusted net income was $23 million USD in 2022 (2021 – $16 million USD). For a reconciliation of Other Electric Utilities adjusted net income to consolidated net income, refer to the "Non-GAAP Financial Measures and Ratios" 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 <u>www.sedar.com</u>.

**Seasonal Nature** 

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

**Capital Investment** 

Other Electric Utilities capital investments (including AFUDC) for 2022 were $48 million USD (2021 – $88 million USD). In 2023, capital investment is expected to be approximately $65 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.

***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 per cent joint venture ownership of Bear Swamp, a 660 MW pumped storage hydroelectric facility in northwestern Massachusetts. ETL is a wholly owned technology company focused on finding ways to deliver renewable and resilient energy to customers.

Corporate items included in the Other segment are certain corporate-wide functions including executive management, strategic planning, treasury services, legal, financial reporting, tax planning, corporate business development, corporate governance, investor relations, risk management, insurance, acquisition and disposition related costs, gains or losses on select assets sales, and corporate human resource activities. It includes interest revenue on intercompany financings and interest expense on corporate debt in both Canada and the US. It also includes costs associated with corporate activities that are not directly allocated to the operations of Emera's subsidiaries and investments.

*Emera Incorporated – 2022 Annual Information Form* *18*

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**Emera Energy** 

EES derives revenue and earnings from the wholesale marketing and trading of natural gas and electricity within the company's risk tolerances, including those related to value-at-risk 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, United States Gulf Coast and Midwest/Central Canadian natural gas markets. Its counterparties include electric and gas utilities, natural gas producers, electricity generators and other marketing and trading entities. EES operates in a competitive environment, and the business relies on knowledge of the region's energy markets, understanding of pipeline and transmission infrastructure, a network of counterparty relationships and a focus on customer service. EES manages its commodity risk by limiting open positions, utilizing financial products to hedge purchases and sales, and investing in transportation capacity rights to enable movement across its portfolio.

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).

**Contribution to Consolidated Net Income and Adjusted Net Income** 

Other's contribution to consolidated net income was a loss of $39 million in 2022 (2021 - loss of $412 million). Other's contribution to consolidated adjusted net income was a loss of $218 million in 2022 (2021 – loss of $198 million).For further information on the non-GAAP measure adjusted net income, refer to the "Non-GAAP Financial Measures and Ratios" 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 <u>www.sedar.com</u>.

**Capital Investment** 

Capital investments in the Other segment were $6 million in 2022 (2021 – $5 million). In 2023, capital investment in the Other segment is not expected to be significant.

**GENERAL DEVELOPMENT OF THE BUSINESS** 

***Three Year History and Changes Expected in 2023***

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.

***Florida Electric Utility***

**Base Rate Adjustments – Approval of 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. On October 21, 2021, the FPSC approved a settlement agreement filed by Tampa Electric. The settlement agreement allows for an increase of $191 million USD annually, effective January 2022. This increase consisted 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

*Emera Incorporated – 2022 Annual Information Form* *19*

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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. For further information, refer to the "Regulatory Environments – Florida Electric Utility – Base Rates" section of Note 7, Regulatory Assets and Liabilities, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera's profile on SEDAR at <u>www.sedar.com</u>.

On August 16, 2022, the FPSC approved Tampa Electric's request to increase revenue and ROE due to increases in the 30-year United States Treasury bond yield rate. Effective July 1, 2022, the new mid-point ROE is 10.20 per cent, and the range is 9.25 per cent to 11.25 per cent.

**Fuel and Capacity Charges** 

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.

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 April 2022, due to an increase in fuel commodity and capacity costs. This was approved on March 1, 2022 and the rate increase was spread over customer bills from April 1, 2022 through December 2022.

On January 23, 2023, Tampa Electric requested an adjustment to its fuel charges to recover the 2022 fuel under-recovery of $518 million USD over a period of 21 months. The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $170 million USD for the balance of 2023. The proposed changes will be decided by the FPSC in March 2023, and recovery is expected to begin in April 2023.

**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.

During 2017 to 2021, Tampa Electric invested $850 million USD in 600 MW of utility-scale solar photovoltaic projects, which is recoverable through FPSC-approved SoBRAs. AFUDC was earned on these projects during construction. The FPSC has approved SoBRAs representing a total of 600 MW or $104 million USD annually in estimated revenue requirements for in-service projects.

On October 12, 2021, the FPSC approved the true-up filing for SoBRA tranche 3, included in base rates as of January 2020. A $4 million USD true-up was returned to customers during 2021. No true-up for SoBRA tranche 4 was required.

**Big Bend Power Station Modernization** 

Tampa Electric invested $876 million USD, including $91 million USD of AFUDC, during 2018 through 2022 to modernize the Big Bend Power Station. The modernization project repowered Big Bend Unit 1 with natural gas combined-cycle technology and eliminated coal as this unit's fuel. As part of the modernization project, Tampa Electric retired the Unit 1 components that will not be used in the modernized plant in 2020 and Big Bend Unit 2 in 2021. Tampa Electric plans to retire Big Bend Unit 3 in 2023 as it is in the best interest of the customers from an economic, environmental risk and operational perspective.

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, in the

*Emera Incorporated – 2022 Annual Information Form* *20*

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Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera's profile on SEDAR at <u>www.sedar.com</u>.

**Storm Protection Cost Recovery Clause and Settlement Agreement** 

On October 3, 2019, the FPSC issued a rule to implement a Storm Protection Plan ("SPP") Cost Recovery Clause. This clause provides a process for Florida investor-owned utilities, including Tampa Electric, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. Differences between prudently incurred clause-recoverable costs and amounts recovered from customers through electricity rates in a year are deferred and recovered from or returned to customers in a subsequent year. A settlement agreement was approved on August 10, 2020, and Tampa Electric's cost recovery began in January 2021. The current approved plan addressed the years 2020 through 2022, and in April 2022 Tampa Electric submitted a new plan to determine cost recovery in 2023, 2024 and 2025. On October 4, 2022, the FPSC approved Tampa Electric's SPP for those years.

*Storm Reserve – Hurricane Ian* 

In September 2022, Tampa Electric was impacted by Hurricane Ian. Total restoration costs were $126 million USD, with $119 million USD of restoration costs charged against Tampa Electric's FPSC approved storm reserve. Total restoration costs charged to the storm reserve have exceeded the reserve balance and have been deferred as a regulatory asset for future recovery. On January 23, 2023, Tampa Electric petitioned the FPSC for recovery of the storm reserve regulatory asset and the replenishment of the balance in the reserve to the previous approved reserve level of $56 million USD, for a total of approximately $131 million USD. The proposed changes will be decided by the FPSC in March 2023 and recovery is expected to begin in April 2023 through March 2024.

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, in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera's profile on SEDAR at <u>www.sedar.com</u>.

***Canadian Electric Utilities***

*NSPI* 

**Environmental Legislation and Regulations** 

There have been several recent environmental developments in Canada at both the federal and provincial levels, as described further below. NSPI continues to work with both the provincial and federal governments on measures to address their carbon reduction goals. Future compliance with provincial and federal GHG emission caps, coal phase out requirements and targets, and renewable standards has been challenged as a result of the constraints imposed by the enactment of Bill 212, "Public Utilities Act (amended)".

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.

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 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.

*Emera Incorporated – 2022 Annual Information Form* *21*

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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. 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.

In March 2022 the federal government issued their 2030 Emission Reduction Plan required under the Canadian Net-Zero Emissions Accountability Act. The Emission Reduction Plan acknowledges the federal and provincial emission reduction goals and programs currently legislated and also signals the intention for implementation of further emission reduction goals, including the federal intention of attaining a net-zero electricity grid by 2035. Subsequent regulations will be required to detail how this goal will be achieved.

*Carbon Pricing Regulations* 

On November 9, 2022, the Nova Scotia provincial government enacted Bill 208, "Environment Act (amended)". The legislation provides the framework for Nova Scotia's system to comply with the federal government's 2023 through 2030 carbon pollution pricing regulations laid out in the Pan-Canadian Framework on Clean Growth and Climate Change. Nova Scotia's proposed system utilizes an output-based pricing system that will implement performance standards for large industrial greenhouse gas emitters to achieve emission reduction goals. Subsequent regulations will be required to detail how the pricing system will operate. The Province of Nova Scotia's proposed output-based pricing system is subject to the approval of the federal government. If an agreement is not reached between the federal and provincial governments on a Nova Scotia system that meets the federal compliance criteria, Nova Scotia will be subject to the federal carbon pollution pricing backstop which uses emissions performances standards that vary by fuel type, and a carbon price that will start at $65 per tonne in 2023 and increase by $15 per tonne annually, reaching $170 per tonne by 2030. NSPI's regulatory framework provides for the recovery of costs prudently incurred to comply with carbon pricing programs pursuant to NSPI's FAM.

**General Rate Application** 

On November 9, 2022, the Nova Scotia provincial government enacted Bill 212, "Public Utilities Act (amended)". The legislation limits non-fuel rate increases in NSPI's GRA filed in 2022, excluding increases relating to demand-side management costs, to a total of 1.8 per cent between the effective date of the UARB's decision and the end of 2024. The legislation also:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;● requires revenue generated from the non-fuel rate increase to be used only to
improve the reliability of service to ratepayers,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;● limits NSPI's return on equity to 9.25 per cent and equity ratio to 40 per cent, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;● limits the rate used to accrue interest on regulatory deferrals to the Bank of Canada policy interest rate plus
1.75 per cent, unless otherwise directed by the UARB.

Actions required to address the impact of Bill 212, "Public Utilities Act (amended)", include a material reduction in NSPI's planned capital investments and operating costs over the 2023 through 2024 period. Such deferral of capital investment and operating costs may result in higher customer costs in future periods. The legislation will have a direct and negative impact on the financial performance of NSPI and has had a negative impact on NSPI's credit quality. For more information on this risk, refer to the "Risk Management and Financial Instruments – Regulatory and Political Risk" section of the MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera's profile on SEDAR at <u>www.sedar.com</u>.

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On November 24, 2022, NSPI filed with the UARB a comprehensive settlement agreement between NSPI, key customer representatives and participating interest groups ("NSPI Settlement Agreement") in relation to its GRA filed in January 2022. The NSPI Settlement Agreement was structured to be consistent with the amendments to the Public Utilities Act made under Bill 212, including the 1.8 per cent cap on non-fuel rate increases for 2023 and 2024. Bill 212, "Public Utilities Act (amended)" is described further, above. The NSPI Settlement Agreement also addresses the recovery of fuel costs over the settlement period and establishes a demand-side management rider. This will result in a combined fuel and non-fuel rate increase of 6.9 per cent each year for 2023 and 2024, and annualised incremental revenue (fuel and non-fuel) of $105 million in 2023 and $115 million in 2024. In addition, any under or over recovery of fuel costs will be addressed through the UARB's established FAM process. NSPI's ROE range will continue to be 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 40 per cent. The NSPI Settlement Agreement also establishes a storm rider for each of 2023, 2024 and 2025, which gives NSPI the option to apply to the UARB for recovery of costs if major storm restoration expense exceeds approximately $10 million in a given year. On February 2, 2023, NSPI received the UARB's decision, which substantially approved the NSPI Settlement Agreement as filed. Approved rate increases will be effective as of the date of the decision.

**Hurricane Fiona** 

On September 24, 2022, Nova Scotia was struck by Hurricane Fiona, which made landfall as a post-tropical storm equivalent to a Category 2 hurricane. The storm had sustained winds of over 100 kilometres per hour and peak gusts of approximately 180 kilometres per hour. This historic storm for Nova Scotia caused significant and widespread damage to NSPI's transmission and distribution system and at the height of the storm approximately 415,000 customers lost power. The total cost of the restoration was approximately $115 million, of which $91 million was capitalized to Property, plant and equipment ("PP&E") and $24 million deferred to Other long-term assets for future amortization, subject to UARB approval. NSPI intends to submit an application to the UARB requesting to defer the recognition of incremental operating costs related to storm restoration. If the deferral is approved, this balance will be reclassified to "Regulatory assets" and amortized over the UARB approved recognition period.

**Regulatory Matters – General** 

NSPI operated under a three-year fuel stability plan which resulted in an average annual overall rate increase of 1.5 per cent to recover fuel costs for the period of 2020 through 2022. These rates included recovery of Maritime Link costs, as discussed below. 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.

*Nova Scotia Cap-and-Trade Program Regulations* 

NSPI is a participant in the Nova Scotia Cap-and-Trade Program and is subject to the 2019 through 2022 compliance period. For more information, refer to the "Description of the Business – Canadian Electric Utilities - Environmental Considerations" section above.

**Regulatory Matters – Maritime Link** 

The Maritime Link entered service on January 15, 2018 and NSPI started interim assessment payments to NSPML at that time. As part of a three-year fuel stability plan, electricity rates were set to include amounts of $164 million and $162 million for 2021 and 2022, respectively. Any difference between the amounts

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included in the fuel stability plan and those approved by the UARB through the NSPML interim assessment application will be addressed through the FAM.

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

*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 currently anticipated to take place in 2023.

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.

In February 2022, the UARB issued its decision and Board Order approving NSPML's requested rate base of approximately $1.8 billion less $9 million of costs ($7 million after-tax) that would not have otherwise been recoverable if incurred by NSPI. NSPML also received approval to collect up to $168 million (2021 – $172 million) from NSPI for the recovery of costs associated with the Maritime Link in 2022. This was subject to a holdback of up to $2 million per month, beginning April 2022, release of which was contingent on receiving in that month at least 90 per cent of NS Block deliveries, including supplemental Energy deliveries.

In December 2022, NSPML received UARB approval to collect up to $164 million from NSPI for the recovery of costs associated with the Maritime Link in 2023. This continues to be subject to a holdback up to $2 million a month, on the same terms described above. On December 22, 2022, the UARB clarified its earlier direction regarding the holdback and NSPI can now release the holdback to NSPML when 90 per cent of the NS Block deliveries, including Supplemental Energy deliveries, is achieved. This enabled NSPI to pay NSPML approximately $4 million of the 2022 holdback. As of December 31, 2022, an additional $14 million in aggregate has been held back by NSPI. Allocation of the $14 million between NSPML and NSPI will be subject to a regulatory process that is expected to commence in early 2023 to review the holdback mechanism.

**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. For further information on the NS Block, refer to the "Business Overview and Outlook – Canadian Electric Utilities" and "Contractual Obligations" sections of the MDA, which is hereby incorporated by reference, a copy of which is available electronically under Emera's profile on SEDAR at <u>www.sedar.com</u>.

***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. It provides PGS the ability to reverse a

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total of $34 million USD of accumulated depreciation through 2023 and sets new depreciation rates effective January 1, 2021. During 2022, PGS reversed $14 million USD of the $34 million USD accumulated depreciation. No amounts were reversed prior to 2022.

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.

**Base Rate** 

On February 3, 2023, PGS notified the FPSC that it is planning to file a base rate proceeding in April 2023 for new rates effective January 2024. For more information refer to the "Business Overview and Outlook – Gas Utilities and Infrastructure - Gas Utilities and Infrastructure Outlook" section of the MDA, which is hereby incorporated by reference, a copy of which is available electronically under Emera's profile on SEDAR at <u>www.sedar.com</u>.

*NMGC* 

**Settlement Agreements** 

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.

On December 13, 2021, NMGC filed a rate case with the NMPRC for new rates to become effective January 2023. On May 20, 2022, NMGC filed an unopposed settlement agreement with the NMPRC for an increase of $19 million USD in annual base revenues. The rates reflect the recovery of increased operating costs and capital investments in pipelines and related infrastructure. The NMPRC approved the settlement agreement on November 30, 2022.

**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.

***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).

***ECI***

**BLPC General Rate Review** 

On October 4, 2021 BLPC submitted a general rate review application to the FTC. The application seeks a rate adjustment and the implementation of a cost reflective rate structure that will facilitate the changes expected in the newly reformed electricity market and the country's transition toward 100 per cent

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renewable energy generation. The application seeks recovery of capital investment in plant, equipment and related infrastructure and results in an increase in annual non-fuel revenue of approximately $23 million USD upon approval. The application includes a request for an allowed regulatory ROE of 12.50 per cent on an allowed equity capital structure of 65 per cent.

On September 16, 2022, the FTC granted BLPC interim rate relief, allowing an increase in base rates of approximately $3 million USD for the remainder of 2022 and approximately $1 million USD per month for 2023. Interim rate relief is effective from September 16, 2022 until the implementation of final rates. The hearing concluded in October 2022. On February 15, 2023, the FTC issued a decision on the BLPC rate review application which included the following significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent, a directive to update the major components of rate base to September 16, 2022, and a directive to establish regulatory liabilities of approximately $70 million USD related to the self-insurance fund, accumulated depreciation, and taxes. The impacts to BLPC's rate base and final rates are not yet determinable but management does not expect the decision to have a material impact on Emera's adjusted net income. BLPC will seek to clarify aspects of the FTC decision in its compliance filing and is also considering filing a submission to the FTC for a review of the decision. BLPC expects a decision on final rates from the FTC in 2023.

**BLPC Licenses** 

BLPC is regulated by the Fair Trading Commission ("FTC"), an independent regulator, under the Utilities Regulation (Procedural) Rules 2003. BLPC currently operates pursuant to a franchise to generate, transmit and distribute electricity on the island until 2028. In 2019, the Government of Barbados passed legislation amending the number of licenses required for the supply of electricity from a single integrated license which currently exists to multiple licenses for Generation, Transmission and Distribution, Storage, Dispatch and Sales. In March 2021, BLPC reached commercial agreement with the Government of Barbados for each of the license types, subject to the passage of implementing legislation. The new licenses are expected to take effect in 2023 on completion of the legislative process. The Dispatch license will have a term of five years with the remaining licenses having terms ranging from 25-30 years. BLPC anticipates that any increased costs associated with the implementation of the new multi-licensed structure will be recoverable through BLPC's regulatory framework. BLPC is awaiting final enactment and will work towards implementation of the licenses once received.

**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 2023.

**GBPC Storm Restoration Costs – Hurricane Matthew** 

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

**GBPC Base Rates** 

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

*Emera Incorporated – 2022 Annual Information Form* *26*

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**GBPC Fuel Recovery** 

Effective November 1, 2022, GBPC's fuel pass through charge was increased due to an increase in global oil prices impacting the unhedged fuel cost. In 2023 the fuel pass through charge will be adjusted monthly, in-line with actual fuel costs.

***USGAAP – Exemptive Relief***

On January 28, 2021, the International Accounting Standards Board ("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. Emera was granted exemptive relief by Canadian securities regulators on September 13, 2022, and under the Companies Act (Nova Scotia) on October 12, 2022, each allowing Emera to continue to report its financial results in accordance with USGAAP (collectively the "Exemptive Relief"). The Exemptive Relief will terminate on the earliest of: (i) January 1, 2027; (ii) if the Company ceases to have rate-regulated activities, the first day of the Company's financial year that commences after the Company ceases to have rate-regulated activities; and (iii) the first day of the Company's financial year that commences on or following the later of: (a) the effective date prescribed by the IASB for the mandatory application of a standard within IFRS specific to entities with rate-regulated activities ("Mandatory Rate-regulated Standard"); and (b) two years after the IASB publishes the final version of a Mandatory Rate-regulated Standard. The Exemptive Relief replaces similar relief that had been granted to Emera in 2018 and would have expired by no later than January 1, 2024.

The Company will continue to monitor the development of the Mandatory Rate-regulated Standard and assess the impact on the existing Exemptive Relief.

***Financing Activity***

**At-The-Market Equity 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 after-tax issuance costs). As at December 31, 2020, an aggregate gross sales limit of $245 million remained available for issuance under the ATM 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.

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 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.

During 2022, approximately 4.07 million common shares were issued under the ATM Program at an average price of $61.31 per share for gross proceeds of $250 million ($248 million net of after-tax issuance costs). As at December 31, 2022, an aggregate gross sales limit of $207 million remained available for issuance under the ATM Program.

During 2023, up to and including February 22, 2023, no common shares were issued under the ATM Program and an aggregate gross sales limit of $207 million remains available for issuance under the ATM Program.

*Emera Incorporated – 2022 Annual Information Form* *27*

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**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. 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 <u>www.sedar.com</u>.

**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 <u>www.sedar.com</u>.

**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.

*Emera Incorporated – 2022 Annual Information Form* *28*

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As at December 31, 2022, 269,944,308 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.

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, 2022, 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, 2022, 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

*Emera Incorporated – 2022 Annual Information Form* *29*

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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.

**CREDIT RATINGS** 

Emera has the following credit ratings by the Rating Agencies:

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| | | | |
|:---|:---|:---|:---|
|  | **Moody's** | **S&P** | **Fitch** |
| &nbsp;&nbsp;&nbsp; Corporate | Baa3 | BBB | BBB |
| &nbsp;&nbsp;&nbsp; Outlook | Negative | Negative | Negative |
| &nbsp;&nbsp;&nbsp; Senior unsecured debt program | Baa3 | BBB- | BBB |
| &nbsp;&nbsp;&nbsp; Hybrid Notes | Ba2 | BB+ | BB+ |
| &nbsp;&nbsp;&nbsp; First Preferred Shares | N/A | P-3 (high) | N/A |

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Ratings are intended to provide investors with an independent measure of the credit quality of an issue of securities 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 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 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 circumstances so warrant.

**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

*Emera Incorporated – 2022 Annual Information Form* *30*

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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. 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.

For further information on the credit ratings of Emera and its subsidiaries, including the recent downgrades from both S&P and DBRS of NSPI, refer to the "Credit Ratings" 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 <u>www.sedar.com</u>.

**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 22, 2022 Emera extended its annual dividend growth rate target of four to five per cent through 2025. 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 2022.

*Emera Incorporated – 2022 Annual Information Form* *31*

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

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| | | | |
|:---|:---|:---|:---|
| &nbsp;&nbsp;&nbsp;**Class of Shares** | **2022** | **2021** | **2020** |
| &nbsp;&nbsp;&nbsp; Common Shares<sup>(1), (2), (3)</sup>  | $2.6775 | $2.5750 | $2.4750 |
| &nbsp;&nbsp;&nbsp; Series A First Preferred Shares<sup>(4)</sup>  | $0.5456 | $0.5456 | $0.6155 |
| &nbsp;&nbsp;&nbsp; Series B First Preferred Shares | $0.6869 | $0.4873 | $0.6965 |
| &nbsp;&nbsp;&nbsp; Series C First Preferred Shares<sup>(5)</sup>  | $1.18024 | $1.18024 | $1.18024 |
| &nbsp;&nbsp;&nbsp; Series E First Preferred Shares | $1.1250 | $1.1250 | $1.1250 |
| &nbsp;&nbsp;&nbsp; Series F First Preferred Shares<sup>(6)</sup>  | $1.05052 | $1.05052 | $1.053515 |
| &nbsp;&nbsp;&nbsp; Series H First Preferred Shares<sup>(7)</sup>  | $1.2250 | $1.2250 | $1.2250 |
| &nbsp;&nbsp;&nbsp; Series J First Preferred Shares<sup>(8)</sup>  | $1.0625 | $0.646965 | - |
| &nbsp;&nbsp;&nbsp; Series L First Preferred Shares<sup>(9)</sup>  | $1.1500 | $0.1638 | - |

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1) On September 16, 2020, Emera approved an increase in the annual common share dividend rate from $2.45 to $2.55.
The first payment was effective November, 2020.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(2) On September 24, 2021, Emera approved an increase in the annual common share dividend rate from $2.55 to $2.65.
The first payment was effective November 15, 2021.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(3) On September 22, 2022, Emera approved an increase in the annual common share dividend rate from $2.65 to $2.76.
The first payment was effective November 15, 2022.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(4) The Series A First Preferred Shares annual dividend rate was reset from $0.6388 to $0.5456 for the five year period
commencing August 15, 2020 and ending on (and inclusive of) August 14, 2025.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(5) The Series C First Preferred Shares annual dividend rate was reset from $1.0250 to $1.18024 for the five year period
commencing August 15, 2018 and ending on (and inclusive of) August 14, 2023.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(6) The Series F First Preferred Shares annual dividend rate was reset from $1.0625 to $1.0505 for the five year period
commencing February 15, 2020 and ending on (and inclusive of) February 14, 2025.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(7) The Series H First Preferred Shares with an annual dividend rate of $1.2250 (per share) were issued May 31, 2018.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(8) The Series J First Preferred Shares with an annual dividend rate of $1.0625 (per share) were issued April 6, 2021.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(9) The Series L First Preferred Shares with an annual dividend rate of $1.150 (per share) were issued September 24,
2021. 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.

**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 2022 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

*Emera Incorporated – 2022 Annual Information Form* *32*

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remain in effect until September 5, 2023. As at December 31, 2022, an aggregate gross sales limit of approximately $207 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.

**DIRECTORS AND OFFICERS** 

***Directors***

The following information is provided for each Director of Emera as at December 31, 2022<sup>(1)</sup>:

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| | | |
|:---|:---|:---|
| &nbsp;&nbsp;&nbsp;**Name, Residence, Principal Occupations During the Past Five Years** | **Director<br>Since<sup>(2)</sup>** | **Committees<sup>(3)</sup>** |
| &nbsp;&nbsp;&nbsp; **M. Jacqueline Sheppard (Chair), Calgary, Alberta, Canada**<br> Chair of the Board since May 2014. Director of Suncor Energy Inc., a Canadian integrated energy company and of ARC Resources Ltd., a publicly traded Canadian energy company. Director of Alberta Investment Management Corporation (AIMCo), an institutional investment manager.<sup>(1)</sup> Former Executive Vice President, Corporate and Legal of Talisman Energy Inc. Founder and former Lead Director of Black Swan Energy Inc., an Alberta upstream energy company, which was sold in July 2021. Former Director of Cairn Energy PLC, a publicly traded UK-based international upstream company and Chair of the Research and Development Corporation of the Province of Newfoundland and Labrador, a provincial Crown corporation, until June 2014. | 2009 | (4) |
| &nbsp;&nbsp;&nbsp; **Scott C. Balfour, Halifax, Nova Scotia, Canada**<br> A Director and President and Chief Executive Officer of Emera since March 29, 2018. Mr. Balfour is a Director of many Emera 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 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 Ontario Energy Association. | 2018 | (5) |
| &nbsp;&nbsp;&nbsp; **James V, Bertram Calgary, Alberta, Canada**<br> Chair of the Board, Keyera Corporation. Formerly President, and Chief Executive Officer of Keyera from its inception in 1998 until 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 markets. | 2018 | &nbsp;&nbsp; Chair of HSEC and Member of MRCC |
| &nbsp;&nbsp;&nbsp; **Henry E. Demone, Lunenburg, Nova Scotia, Canada**<br> Former Chair of High Liner Foods, the leading North American processor and marketer of value-added frozen seafood. Mr. Demone was 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 | &nbsp;&nbsp; Chair of MRCC and Member of<br> NCGC |
| &nbsp;&nbsp;&nbsp; **Paula Y. Gold-Williams, San Antonio, Texas, U.S.**<br> Former President and CEO of CPS Energy, a fully integrated electric and natural gas municipal utility based in San Antonio, Texas. Currently serves as the Chair of the Keystone Policy Center, having been a member of both the Policy Center and its Energy Board since 2016. Board member and Treasurer of EPIcenter, an innovation think tank; incubator and accelerator; and strategic advisory organization. Energy Pillar Co-Chair of Dentons' Global Smart Cities & Communities Initiatives and Think Tank. Advisory Board Member of iEmpower, an all-inclusive organization that optimizes the concept of community to engage and inspire women. Serves on the US Secretary of Energy's Advisory Board. | 2022 | &nbsp;&nbsp; Member of AC and HSEC |

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*Emera Incorporated – 2022 Annual Information Form* *33*

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| | | |
|:---|:---|:---|
| &nbsp;&nbsp;&nbsp;**Name, Residence, Principal Occupations During the Past Five Years** | **Director<br>Since<sup>(2)</sup>** | **Committees<sup>(3)</sup>** |
| &nbsp;&nbsp;&nbsp; **Kent M. Harvey, New York, New York, U.S.**<br> Former Chief Financial Officer for PG&E Corporation, an energy-based holding company, and the parent of Pacific Gas and Electric Company, an energy company that provides gas and electric service to approximately 16 million Californians across a 70,000 square-mile service area in Northern and Central California. | 2017 | &nbsp;&nbsp; Chair of AC and Member of HSEC |
| &nbsp;&nbsp;&nbsp; **B. Lynn Loewen, FCPA, FCA, Westmount, Quebec, Canada**<br> Former President of Minogue Medical Inc., a healthcare organization which delivers innovative medical technologies to hospitals and clinics. President of Expertech Network Installation Inc. from 2008 to 2011. Member of the Board of Directors of National Bank of Canada, a Canadian Chartered Bank. Director of Xplore Communications Inc., a Canadian broadband service provider, and Chair of its Audit Committee. | 2013 | &nbsp;&nbsp; Member of AC, HSEC and RSC |
| &nbsp;&nbsp;&nbsp; **Ian E. Robertson, Oakville, Ontario, Canada**<br> Principal 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. Former CEO of Algonquin Power & Utilities Corp. (Algonquin Power. Member of the Board of Directors of Northern Genesis Acquisition Corp. III and a Director of Embark Technology, Inc., an autonomous vehicle company. Former Director of Largo Resources Ltd., Algonquin Power. and Atlantica Sustainable Infrastructure plc. | 2022 | &nbsp;&nbsp; Member of AC and RSC |
| &nbsp;&nbsp;&nbsp; **Andrea S. Rosen, Toronto, Ontario, Canada**<br> Former Vice-Chair of TD Bank Financial Group and President of TD Canada Trust. Director of Manulife Financial Corporation, a Canadian 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 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 | &nbsp;&nbsp; Chair of NCGC and Member of AC |
| &nbsp;&nbsp;&nbsp; **Richard P. Sergel, Boston, Massachusetts, U.S.**<br> Former President and Chief Executive Officer of the North American Electric Reliability Corporation (NERC). Former President and 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 Electric Institute and the Consortium for Energy Efficiency. | 2010 | &nbsp;&nbsp; Member of AC and NCGC |
| &nbsp;&nbsp;&nbsp; **Karen H. Sheriff, Picton, Ontario, Canada**<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 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. She is a former member of the Board of Directors of CPP Investments and WestJet Airlines Ltd. | 2021 | &nbsp;&nbsp; Member of MRCC and RSC |
| &nbsp;&nbsp;&nbsp; **Jochen E. Tilk, Toronto, Ontario, Canada**<br> Former Executive Chair of Nutrien Ltd., a Canadian global supplier of agricultural products and services based in Saskatoon, 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 AngloGold Ashanti Limited, a publicly listed international gold mining company, headquartered in Johannesburg, South Africa. He is also Vice-Chair of the Princess Margaret Cancer Foundation, a not-for-profit organization. He is the former Chair of the board of directors of Canpotex Limited. Former Director of the Fertilizer Institute and the International Fertilizer Association. | 2018 | &nbsp;&nbsp; Chair of RSC and Member of MRCC and NCGC |

---

(1) Effective May 26, 2022, John B. Ramil retired from the Emera Board of Directors. Effective January 1, 2023,
Ms. Sheppard retired from the AIMCo Board of Directors.

*Emera Incorporated – 2022 Annual Information Form* *34*

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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
the termination of Emera's annual general meeting;

(3) Audit Committee (AC), Health, Safety and Environment Committee (HSEC), Management Resources and Compensation Committee
(MRCC), Nominating and Corporate Governance Committee (NCGC), and Risk and Sustainability Committee (RSC);

(4) Ms. Sheppard is not a member of any committee but attends all committee meetings as Chair of the Board;

(5) Mr. Balfour is not a member of any committee as he is the President and Chief Executive Officer of the Company but
attends all committee meetings.

***Officers***

The Officers of Emera as at December 31, 2022 were as follows:

---

| | |
|:---|:---|
| &nbsp;&nbsp;&nbsp;**Name and Residence** | **Principal Occupations During the Past Five Years** |
| &nbsp;&nbsp;&nbsp; **Scott C. Balfour**<br> President and Chief Executive Officer<br> Halifax, Nova Scotia, Canada | A Director and President and Chief Executive Officer of Emera since March 29, 2018.<sup>(1)</sup> |
| &nbsp;&nbsp;&nbsp; **Gregory W. Blunden, FCPA**<br> Chief Financial Officer<br> Halifax, Nova Scotia, Canada | Chief Financial Officer of Emera since March 2016. |
| &nbsp;&nbsp;&nbsp; **Karen E. Hutt**<br> Executive Vice-President, Business Development and Strategy<br> Halifax, Nova Scotia, Canada | Executive Vice-President, Business Development and Strategy of Emera since October 21, 2019. Previously, President and Chief Executive Officer of NSPI since August 2016. |
| &nbsp;&nbsp;&nbsp; **Richard C. Janega <sup>(2)</sup>**<br> Chief Operating Officer, Electric Utilities, Canada and Caribbean<br> Halifax, Nova Scotia, Canada | Chief Operating Officer, Electric Utilities, Canada, US Northeast, and Caribbean of Emera since March 31, 2018. Director of NSPI 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 2014. Chair and President of ECI and Chair of both GBPC and BLPC. Former Chief Operating Officer for NSPI. |
| &nbsp;&nbsp;&nbsp; **Bruce A. Marchand**<br> Chief Risk and Sustainability Officer Halifax, Nova Scotia, Canada | Chief Risk and Sustainability Officer of Emera since June 30, 2022. Prior to this Chief Legal and Compliance Officer of Emera and NSPI since December 1, 2014 and Chief Legal Officer of Emera and NSPI since January 2012. |
| &nbsp;&nbsp;&nbsp; **R. Michael Roberts**<br> Chief Human Resources Officer<br> Halifax, Nova Scotia, Canada | Chief Human Resources Officer of Emera and NSPI since December 1, 2014. |
| &nbsp;&nbsp;&nbsp; **Daniel P. Muldoon**<br> Executive Vice-President Project Development and Operations Support<br> Halifax, Nova Scotia, Canada | Executive Vice-President Project Development and Operations Support of Emera. Chair of the Boards of ENL, EBPC, Emera Technologies 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. |
| &nbsp;&nbsp;&nbsp; **Michael R. Barrett**<br> Executive Vice-President and General Counsel<br> Halifax, Nova Scotia, Canada | Executive Vice-President and General Counsel of Emera since July 1, 2022. Prior to this, General Counsel of Emera since November 20, 2017. Prior to joining Emera, Senior Partner and head of the power and climate change practice groups at Bennett Jones LLP in Toronto. |
| &nbsp;&nbsp;&nbsp; **Stephen D. Aftanas**<br> Corporate Secretary<br> Halifax, Nova Scotia, Canada | Corporate Secretary of Emera since September 2008. Corporate Secretary of NSPI from September 2008 to December 2019. |

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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(2) Effective December 31, 2022, Mr. Janega retired from Emera and certain subsidiaries and/or subsidiary boards.
Following his retirement, Mr. Janega will serve or continue to serve on the following subsidiary boards: BLPC, ECI, ENLH, GBPC and NSPI.

*Emera Incorporated – 2022 Annual Information Form* *35*

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As at December 31, 2022, the Directors and Officers, in total, beneficially owned or controlled, directly or indirectly, 204,365 common shares or less than 1 per cent of the issued and outstanding shares of Emera.

**AUDIT COMMITTEE** 

The Audit Committee of Emera is composed of the following six members, all of whom are independent Directors: Kent M. Harvey (Chair), Paula Gold-Williams, B. Lynn Loewen, Ian E. Robertson, 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.

**Paula Y. Gold-Williams** 

She is the former President and CEO of CPS Energy, a fully integrated electric and natural gas municipal utility based in San Antonio, Texas. Ms. Gold-Williams served in positions of increasing responsibility at CPS Energy before becoming CEO in 2015. She held multiple other positions during her 17-year career at CPS Energy, including Group EVP – Financial & Administrative Services, CFO and Treasurer. Chair of the Keystone Policy Center, and member of both the Policy Center and its Energy Board since 2016. Board member and Treasurer of EPIcenter, an innovation think tank; incubator and accelerator; and strategic advisory organization. Formerly, First Vice Chair of the Electric Power Resource Institute (EPRI); a member and designated Chair Pro Tem of the Federal Reserve Bank of Dallas' San Antonio Branch; and a past-Chair of the San Antonio Chamber of Commerce. She holds an Associate Degree in Fine Arts from San Antonio College and a BBA in accounting from St. Mary's University. She earned a Finance and Accounting MBA from Regis University in Denver, Colorado. She is a Certified Public Accountant and a Chartered Global Management Accountant.

**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. Chancellor of Mount Allison University since 2018 and was a member of the Board from 1998 to 2008. Served as Chair from 2007 to 2008.. She holds a Bachelor of Commerce from Mount Allison University. Fellow of the Chartered Professional Accountants and has received the Institute of Corporate Directors, Directors Designation.

*Emera Incorporated – 2022 Annual Information Form* *36*

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**Ian E. Robertson** 

Principal 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. Former CEO of Algonquin Power & Utilities Corp. (Algonquin Power), a publicly traded, diversified international generation, transmission, and distribution utility. Founder and principal of Algonquin Power Corporation Inc., a private independent power developer formed in 1988 and predecessor organization to Algonquin Power. Over 30 years of experience in the development of electric power generating projects and the operation of diversified regulated utilities. Member of the Board of Directors of Northern Genesis Acquisition Corp. III and a Director of Embark Technology, Inc., an autonomous vehicle company. Former Director of Largo Resources Ltd., Algonquin Power and Atlantica Sustainable Infrastructure plc. Mr. Robertson is an electrical engineer and holds a Professional Engineering designation through his Bachelor of Applied Science degree awarded by the University of Waterloo. He earned a Master of Business Administration degree from York University's Schulich School of Business. He holds a Chartered Financial Analyst designation, as well as a global professional Master of Laws degree from the University of Toronto. He received a Chartered Director designation from the Directors College of McMaster University. Since 2013, Mr. Robertson is a former member of the board of directors of the American Gas Association.

**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. 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,

*Emera Incorporated – 2022 Annual Information Form* *37*

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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, 2022 and 2021 respectively, were as follows:

---

| | | |
|:---|:---|:---|
| &nbsp;&nbsp;&nbsp; **Service Fee** | **2022 ($)** | **2021 ($)** |
| &nbsp;&nbsp;&nbsp;&nbsp; **Audit Fees** | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2018989 | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2078760 |
| &nbsp;&nbsp;&nbsp;&nbsp; **Audit-Related Fees** | 19600 | 19600 |
| &nbsp;&nbsp;&nbsp;&nbsp; **Tax Fees** | 337999 | 372618 |
| &nbsp;&nbsp;&nbsp;&nbsp; **All Other Fees** | - | - |
| &nbsp;&nbsp;&nbsp;&nbsp; **Total** | 2376588 | 2470978 |

---

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
executive officer or chief financial officer of any company that:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) was subject to an Order that was issued while the Director or Officer was acting in the capacity as director, chief
executive officer or chief financial officer; or

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) was subject to an Order that was issued after the Director or Officer ceased to be a director, chief executive officer
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;

(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
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
to or instituted any proceedings, arrangements or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets;

(3) have, within the ten years before the date of this AIF, become bankrupt, made a proposal under any legislation
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

(4) have been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a
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
investor making an investment decision.

*Emera Incorporated – 2022 Annual Information Form* *38*

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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 OF MANAGEMENT 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, 2022, nor has it entered into any material contracts outside the ordinary course of business prior to the year ended December 31, 2022 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.

**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 <u>www.sedar.com</u> 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 Incorporated – 2022 Annual Information Form* *39*

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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 <u>www.sedar.com</u> and on its corporate website at <u>www.emera.com</u>.

*Emera Incorporated – 2022 Annual Information Form* *40*

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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 and Ratios" 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 <u>www.sedar.com</u>;

**"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 2022 Annual Information Form of Emera;

"**AMI**" means advanced metering infrastructure;

**"Atlantic Canada"** 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, 2022 and December 31, 2021, together with the auditors' report thereon, a copy of which is available electronically under Emera's profile on SEDAR at <u>www.sedar.com;</u>

**"Bahamas DRs"** means the DRs listed on BISX;

**"Barbados DRs"** means the DRs listed on the BSE;

**"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 Saint John 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;

**"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 formerly an indirect subsidiary of Emera, through ECI;

**"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;

**"ECI"** means Emera (Caribbean) Incorporated, a company incorporated under the laws of Barbados and

*Emera Incorporated – 2021 Annual Information Form* *41*

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an indirect subsidiary of Emera and the parent company of BLPC and GBPC;

**"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.

**"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 Bond Yield"** 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 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;

*Emera Incorporated – 2022 Annual Information Form* *42*

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**"Hybrid Notes"** means the $1.2 billion USD unsecured, fixed-to-floating subordinated notes of Emera due 2076;

**"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;

"**IMP**" means integrity management programs;

**"IPPs"** means independent power producers;

**"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, 2022, a copy of which is available electronically under Emera's profile on SEDAR at <u>www.sedar.com</u>;

**"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;

**"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;

**"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;

**"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, which effective January 1,

*Emera Incorporated – 2022 Annual Information Form* *43*

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2023, ceased to be a division of TEC as a result of the gas utility being reorganized, resulting in a separate legal entity, PGSI;

"**PGSI**" means Peoples Gas System, Inc. (PGSI), the successor to PGS, existing under the laws of the State of Florida, and a wholly-owned direct subsidiary of TECO Gas Operations, Inc.;

"**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;

**"RENAC"** means Repsol Energy North America Canada Partnership;

"**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 RENAC;

**"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;

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

"**SO<sub>2</sub>**" means sulphur dioxide;

**"SoBRA"** means solar base rate adjustment;

**"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 a regulated gas utility in New Mexico;

**"TECO Gas Operations, Inc."** means the wholly-owned subsidiary of TECO Energy, incorporated under

*Emera Incorporated – 2022 Annual Information Form* *44*

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the laws of the State of Florida, and the parent company of PGSI, which as of January 1, 2023, currently owns the regulated gas utility known as PGS, formerly a division of TEC;

**"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

*Emera Incorporated – 2022 Annual Information Form* *45*

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**APPENDIX "B" – Summary of Terms and Conditions of Authorized Series of First Preferred Shares** 

As of December 31, 2022, 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, H and J First Preferred Shares have the right to convert their shares into an equal number of Series B, D, G, I and K 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.

*Emera Incorporated – 2022 Annual Information Form* *46*

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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.

Applicable redemption, conversion, interest and reset dates and spreads are listed in the following table:

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

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**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, 2022, 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.

*Emera Incorporated – 2022 Annual Information Form* *47*

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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.

*Emera Incorporated – 2022 Annual Information Form* *48*

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**APPENDIX "C" - MONTHLY TRADING VOLUME AND HIGH AND LOW PRICE FOR EMERA'S SECURITIES IN 2022** 

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| | | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | &nbsp;&nbsp;&nbsp;&nbsp;**Common** <br> **Shares**  | **Depositary Receipts** | **Depositary Receipts** | <br> **Series of First Preferred Shares** | <br> **Series of First Preferred Shares** | <br> **Series of First Preferred Shares** | <br> **Series of First Preferred Shares** | <br> **Series of First Preferred Shares** | <br> **Series of First Preferred Shares** | <br> **Series of First Preferred Shares** | <br> **Series of First Preferred Shares** |
|  | &nbsp;&nbsp;&nbsp;&nbsp;**Common** <br> **Shares**  | **Barbados** <br> **BBD <sup>(1)</sup>** <br>| <br> **Bahamas** <br> **BSD <sup>(2)</sup>** <br>| **A** | **B** | **C** | **E** | **F** | **H** | **J** | **L** |
| &nbsp;&nbsp;&nbsp; **December**<br> High ($)<br> Low ($)<br> Volume | 54.71<br> 51.14<br> 19,587,632 | 20.17<br> 18.77<br> 0 | 10.09<br> 9.39<br> 0 | 13.75<br> 13.05<br> 45,091 | 16.00<br> 14.60<br> 17,212 | 19.24<br> 18.00<br> 115,362 | 17.75<br> 16.75<br> 90,125 | 17.45<br> 16.76<br> 69,655 | 21.20<br> 19.62<br> 247,927 | 22.42<br> 20.82<br> 191,540 | 18.00<br> 16.99<br> 173,128 |
| &nbsp;&nbsp;&nbsp; **November**<br> High ($)<br> Low ($)<br> Volume | 52.87<br> 48.80<br> 39,025,989 | 19.76<br> 18.08<br> 0 | 9.50<br> 9.50<br> 5000 | 13.77<br> 13.20<br> 30,682 | 16.19<br> 15.25<br> 12,864 | 19.19<br> 17.87<br> 137,332 | 17.84<br> 16.23<br> 211,732 | 17.70<br> 16.72<br> 156,761 | 21.99<br> 20.02<br> 171,893 | 23.17<br> 20.70<br> 81,698 | 17.64<br> 16.40<br> 226,364 |
| &nbsp;&nbsp;&nbsp; **October**<br> High ($)<br> Low ($)<br> Volume | 57.60<br> 48.63<br> 43,502,499 | 21.22<br> 17.65<br> 0 | 9.16<br> 9.16<br> 182 | 14.60<br> 13.21<br> 32,029 | 16.84<br> 16.00<br> 6,750 | 19.32<br> 18.02<br> 109,413 | 17.74<br> 16.51<br> 258,806 | 18.25<br> 17.16<br> 121,392 | 23.00<br> 21.26<br> 105,017 | 23.78<br> 22.61<br> 59,088 | 18.00<br> 16.55<br> 99,867 |
| &nbsp;&nbsp;&nbsp; **September**<br> High ($)<br> Low ($)<br> Volume | 62.92<br> 55.81<br> 18,860,229 | 24.24<br> 20.36<br> 0 | 11.52<br> 11.52<br> 91 | 15.01<br> 13.69<br> 64,662 | 16.77<br> 16.05<br> 16,400 | 20.65<br> 17.75<br> 159,037 | 18.86<br> 17.25<br> 61,824 | 19.90<br> 17.50<br> 92,499 | 24.23<br> 22.15<br> 74,408 | 25.05<br> 23.15<br> 132,314 | 19.12<br> 17.40<br> 56,642 |
| &nbsp;&nbsp;&nbsp; **August**<br> High ($)<br> Low ($)<br> Volume | 63.20<br> 59.05<br> 27,425,695 | 24.33<br> 22.83<br> 0 | 11.67<br> 11.67<br> 274 | 15.60<br> 14.17<br> 16,091 | 16.76<br> 15.65<br> 4,913 | 21.27<br> 19.65<br> 152,090 | 19.88<br> 18.80<br> 46,908 | 20.41<br> 18.63<br> 47,430 | 24.78<br> 23.65<br> 57,246 | 25.48<br> 24.61<br> 53,042 | 19.88<br> 18.90<br> 182,656 |
| &nbsp;&nbsp;&nbsp; **July**<br> High ($)<br> Low ($)<br> Volume | 62.21<br> 59.05<br> 23,355,538 | 23.86<br> 22.90<br> 0 | 11.93<br> 11.45<br> 0 | 15.00<br> 13.51<br> 4,569 | 16.26<br> 15.90<br> 3,505 | 21.56<br> 18.67<br> 59,348 | 19.72<br> 18.60<br> 57,915 | 19.80<br> 17.99<br> 34,075 | 25.09<br> 24.10<br> 100,647 | 25.59<br> 24.80<br> 49,494 | 19.75<br> 18.65<br> 147,790 |
| &nbsp;&nbsp;&nbsp; **June**<br> High ($)<br> Low ($)<br> Volume | 63.76<br> 57.13<br> 18,849,884 | 25.34<br> 21.98<br> 0 | 12.67<br> 10.99<br> 0 | 17.00<br> 15.22<br> 9,784 | 17.50<br> 17.00<br> 2,318 | 23.50<br> 20.52<br> 95,397 | 20.61<br> 18.75<br> 30,649 | 22.92<br> 19.56<br> 48,315 | 25.30<br> 24.32<br> 106,515 | 25.97<br> 25.03<br> 68,631 | 20.76<br> 19.00<br> 88,280 |
| &nbsp;&nbsp;&nbsp; **May**<br> High ($)<br> Low ($)<br> Volume | 64.93<br> 60.63<br> 31,789,311 | 25.29<br> 23.66<br> 0 | 12.65<br> 11.83<br> 0 | 16.48<br> 15.71<br> 4,632 | 16.95<br> 16.49<br> 4,230 | 23.40<br> 21.54<br> 93,901 | 20.27<br> 19.15<br> 136,272 | 22.98<br> 21.05<br> 72,372 | 25.00<br> 24.27<br> 155,320 | 25.96<br> 25.00<br> 57,205 | 20.55<br> 19.60<br> 369,608 |
| &nbsp;&nbsp;&nbsp; **April**<br> High ($)<br> Low ($)<br> Volume | 65.23<br> 61.53<br> 30,128,700 | 26.09<br> 24.59<br> 0 | 13.04<br> 12.29<br> 0 | 16.97<br> 15.46<br> 11,622 | 17.44<br> 16.50<br> 3,908 | 23.50<br> 21.00<br> 321,752 | 22.19<br> 19.85<br> 256,144 | 22.96<br> 20.87<br> 237,026 | 25.35<br> 23.99<br> 180,511 | 25.65<br> 24.90<br> 168,498 | 22.50<br> 19.92<br> 1,971,593 |
| &nbsp;&nbsp;&nbsp; **March**<br> High ($)<br> Low ($)<br> Volume | 62.54<br> 58.82<br> 19,922,299 | 24.48<br> 23.14<br> 0 | 11.25<br> 11.25<br> 1000 | 17.17<br> 16.05<br> 20,242 | 17.60<br> 17.31<br> 4,432 | 24.01<br> 22.81<br> 117,977 | 23.90<br> 22.28<br> 40,237 | 24.38<br> 22.60<br> 56,476 | 25.60<br> 24.75<br> 102,465 | 25.70<br> 24.91<br> 218,688 | 24.44<br> 22.51<br> 107,549 |
| &nbsp;&nbsp;&nbsp; **February**<br> High ($)<br> Low ($)<br> Volume | 60.51<br> 57.87<br> 22,888,998 | 23.83<br> 22.81<br> 0 | 11.92<br> 11.40<br> 0 | 18.60<br> 17.00<br> 20,310 | 18.10<br> 18.02<br> 7,716 | 24.40<br> 23.11<br> 62,044 | 24.33<br> 23.00<br> 45,298 | 24.25<br> 23.30<br> 48,131 | 25.83<br> 24.83<br> 52,126 | 26.51<br> 25.07<br> 88,177 | 24.80<br> 23.95<br> 64,611 |
| &nbsp;&nbsp;&nbsp; **January**<br> High ($)<br> Low ($)<br> Volume | 63.49<br> 58.57<br> 25,752,083 | 24.98<br> 23.14<br> 0 | 12.49<br> 11.57<br> 0 | 18.60<br> 18.01<br> 18,874 | 19.68<br> 18.00<br> 22,004 | 24.64<br> 23.45<br> 128,831 | 25.04<br> 23.85<br> 54,888 | 24.56<br> 23.72<br> 59,256 | 26.60<br> 25.51<br> 80,033 | 27.98<br> 26.07<br> 107,204 | 25.54<br> 24.40<br> 393,203 |

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(1) The Barbados DRs trade on the BSE. During those months in 2022 when the Volume Traded was zero (0), the table above
indicates the high and low trading prices of the Barbados DRs relative to those of Emera's common shares on the TSX.

(2) The Bahamas DRs trade on the BISX. During those months in 2022 when the Volume Traded was zero (0), the table above
indicates the high and low trading prices of the Bahamas DRs relative to those of Emera's common shares on the TSX.

*Emera Incorporated – 2022 Annual Information Form* *49*

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| | |
|:---|:---|
| **February 2023** | ![LOGO](g417839dsp50.jpg) |

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**APPENDIX "D" - EMERA INCORPORATED AUDIT COMMITTEE CHARTER** 

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**PART I** 

**MANDATE AND RESPONSIBILITIES** 

*<u>Committee Purpose</u>*

*There shall be a committee of the Board of Directors (the "Board") of Emera Inc. ("Emera") which shall be known as the Audit 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;* 

*-* *the internal audit and assurance process;* 

*-* *the qualifications, independence and performance of the external auditors;* 

*-* *major financial risk exposures;* 

*-* *Emera's compliance with legal requirements and securities regulations in respect of financial statements and financial reporting; and* 

*-* *any other duties set out in this Charter or delegated to the Committee by the Board.* 

**1.** **Financial Reporting** 

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) The Committee shall be responsible for reviewing, assessing the completeness and clarity of the disclosures
in, and recommending to the Board for approval:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(i) the audited annual financial statements of Emera, all related Management's Discussion and Analysis, and
earnings press releases;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(ii) any documents containing Emera's audited financial statements; and,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(iii) the quarterly financial statements, all related Management's Discussion and Analysis, and earnings
press releases.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) The Board may delegate the approval of the quarterly financial statements, all related Management's
Discussion and Analysis, and earnings press releases to the Committee.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c) The Committee shall oversee and assess that adequate procedures are in place for the review of public
disclosure of financial information.

**2.** **External Auditors** 

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) The Committee shall evaluate and recommend to the Board the external auditor to be nominated for the purpose
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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) Once appointed, the external auditor shall report directly to the Committee, and the Committee shall oversee
the work of the external auditor concerning the preparation or

*Emera Incorporated – 2020 Annual Information Form* *50*

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issuance of the auditor's report or the performance of other audit, review or attest services for Emera.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c) The Committee shall be responsible for resolving disagreements between management and the external auditor
concerning financial reporting.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(d) At least annually, the Committee shall obtain and review a report by the external auditors describing:
(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
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
the auditors' independence).

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(e) The Committee shall annually evaluate the auditors', including the lead audit partner's,
qualifications, performance, professional skepticism and independence.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(f) The Committee shall determine that the external audit firm has a process in place to address the rotation of
the lead audit partner and other audit partners serving the account as required under prescribed independence rules.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(g) Every five (5) years, the Committee shall perform a comprehensive review of the performance of the
external auditors over multiple years to provide further insight on the audit firm, its independence and application of professional standards.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(h) The Committee will review differences that were noted or proposed by the external auditors, but that were
considered immaterial or insignificant; and any "management" or "internal control" letter issued, or proposed to be issued.

**3.** **Non-Audit Services** 

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) The Committee shall be responsible for reviewing and pre-approving all non-audit services to be provided to Emera, or any of its subsidiaries, by the external auditor.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) The Committee may establish specific policies and procedures concerning the performance of non-audit services by the external auditor so long as the requirements of applicable legislation and regulation are satisfied.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c) In accordance with policies and procedures established by the Committee, and applicable legislation and
regulation, the Committee may delegate the pre-approval of non-audit services to a member of the Committee or a sub-committee thereof.

**4.** **Oversight and Monitoring of Audits** 

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) The Committee shall meet with the external auditor prior to the audit to discuss the planning and staffing
of the audit, including the general approach, scope, areas subject to significant risk of material misstatement, estimated fees and other terms of engagement.

*Emera Incorporated – 2022 Annual Information Form* *51*

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) The Committee shall discuss with the external auditor any issues that arise with Management or the internal
auditors during the course of the audit and the adequacy of Management's responses in addressing audit-related deficiencies.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c) The Committee shall regularly review with the external auditors any audit problems or difficulties
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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(d) The Committee shall review with Management the results of internal and external audits.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(e) The Committee shall take such other reasonable steps as it may deem necessary to oversee that the audit was
conducted in a manner consistent with applicable legal requirements and auditing standards of applicable professional or regulatory bodies.

**5.** **Oversight and Review of Accounting Principles and Practices** 

The Committee shall oversee, review and discuss with Management, the external auditor and the internal auditors:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) the quality, appropriateness and acceptability of Emera's accounting principles and practices used in
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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) all significant financial reporting issues and judgments made in connection with the preparation of the
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
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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c) disagreements between Management and the external auditor or the internal auditors regarding the application
of any accounting principles or practices;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(d) any material change to Emera's auditing and accounting principles and practices as recommended by
Management, the external auditor or the internal auditors or which may result from proposed changes to applicable generally accepted accounting principles;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(e) the effect of regulatory and accounting initiatives on Emera's financial statements and other financial
disclosures;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(f) any reserves, accruals, provisions, estimates or Management programs and policies, including factors that
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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(g) the use of special purpose entities and the business purpose and economic effect of off-balance sheet transactions, arrangements, obligations, guarantees and other relationships of Emera and their impact on the reported financial results of Emera;

*Emera Incorporated – 2022 Annual Information Form* *52*

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(h) any legal matter, claim or contingency that could have a significant impact on the financial statements,
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
financial statements;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(i) the treatment for financial reporting purposes of any significant transactions which are not a normal part
of Emera's operations.

**6.** **Hiring Policies** 

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** 

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) The Committee shall review the appointments of key financial executives involved in the financial reporting
process of Emera, including the Chief Financial Officer.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) The Committee may request for review, and shall receive when requested, material tax policies and tax
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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c) The Committee shall meet at least annually with Management to review and discuss Emera's major
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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(d) The Committee may review any investments or transactions that the Committee wishes to review, or which the
internal or external auditor, or any officer of Emera, may bring to the attention of the Committee within the context of this charter.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(e) The Committee shall review financial information of material subsidiaries of Emera and any auditor
recommendations concerning such subsidiaries.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(f) The Committee may request for review, and shall receive when requested, all related party transactions
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.

*Emera Incorporated – 2022 Annual Information Form* *53*

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**9.** **Internal Controls** 

The Committee shall oversee:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) the adequacy and effectiveness of the Company's internal accounting and financial controls and the
recommendations of Management, the external auditor and the internal auditors for the improvement of accounting practices and internal controls; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) management's compliance with the Company's processes, procedures and internal controls.

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:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c) Review and discuss with the Chief Executive Officer and the Chief Financial Officer the procedures
undertaken in connection with the Chief Executive Officer and Chief Financial Officer certifications for the annual and interim filings with applicable securities regulatory authorities.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(d) Review disclosures made by Emera's Chief Executive Officer and Chief Financial Officer during their
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,
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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(e) Discuss with Emera's Chief Legal Officer at least annually any legal matters that may have a material
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.

**10.** **Internal Auditor** 

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) The lead internal auditor shall report directly to the Committee. The Committee shall approve the
appointment, removal and replacement of the lead internal auditor. The Committee shall approve the remuneration of the lead internal auditor on appointment.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) The Committee shall review and approve the internal audit plan, including activities, organizational
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
shall receive reports on the status of significant findings, recommendations, and management's responses.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c) The Committee shall meet periodically with the internal auditor to discuss the progress of their activities,
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.

*Emera Incorporated – 2022 Annual Information Form* *54*

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(d) The Committee shall obtain from the internal auditor and review summaries of the significant reports to
Management prepared by the internal auditor, and the actual reports if requested by the Committee, and Management's responses to such reports.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(e) The Committee shall annually receive and review a report on the Chief Executive Officers' expense
accounts.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(f) The Committee may communicate with the internal auditor with respect to their reports and recommendations,
the extent to which prior recommendations have been implemented and any other matters that the internal auditor brings to the attention of the Committee.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(g) The Committee shall, at least biennially or more frequently as it deems necessary, approve the internal
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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(h) The Committee shall, biennially or more frequently as it deems necessary, review the independence of the
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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(i) The Committee shall review the results of an external assessment, performed every five years by a qualified
independent assessor or assessment team, of the internal audit function in conformance with International Standards for the Professional Practice of Internal Auditing (IPPF Standards).

**11.** **Complaints** 

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. Without limiting the foregoing, the Committee shall receive periodic ethics updates under Emera's Code of Conduct which relate to matters within the scope of responsibility of the Committee as defined in this Charter, and the Committee shall review the related activities within that scope under Emera's Ethics Program, such as financial reporting, accounting and auditing, business integrity, and corporate assets and infrastructure.

**12.** **Other Responsibilities** 

The Committee shall:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) Periodically review Management's process for identifying non-compliance with legal and regulatory requirements;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) Annually receive and review a report on executive officers' compliance with the Company's Code of
Conduct;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c) Annually provide feedback on the performance of the Chief Financial Officer;

*Emera Incorporated – 2022 Annual Information Form* *55*

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(d) Review actions taken by the Company to identify and manage risks related to the Audit Committee mandate,
including Primary Enterprise Risks, which may have the potential to adversely impact the Company's operations, strategy or reputation; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(e) Perform such other duties and exercise such powers as may be directed or delegated to the Committee by the
Board.

**13.** **Limitation on Authority** 

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** 

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) Emera's Articles of Association require that the Committee shall be comprised of no less than three
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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) The Board shall appoint members to the Committee who are financially literate, as required by applicable
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
and complexity of issues that can reasonably be expected to be raised by Emera's financial statements.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c) Committee members shall be appointed at the Board meeting following the election of Directors at
Emera's annual shareholders' meeting and membership may be based upon the recommendation of the Nominating and Corporate Governance Committee.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(d) Pursuant to Emera's Articles of Association, the Board may appoint, remove, or replace any member of
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
shareholders after the member's appointment to the Committee.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(e) The Secretary of the Committee shall advise Emera's internal and external auditors of the names of the
members of the Committee promptly following their election.

*Emera Incorporated – 2022 Annual Information Form* *56*

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**PART III** 

**COMMITTEE PROCEDURE** 

**15.** **Meetings** 

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) Meetings of the Committee may be called by the Chair or at the request of any member. The Committee shall
meet at least quarterly.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) The timing and location of meetings of the Committee, and the calling of and procedure at any such meeting,
shall be determined from time to time by the Committee.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c) Emera's internal and external auditors shall be notified of all meetings of the Committee and shall
have the right to appear before and be heard by the Committee.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(d) Emera's internal or external auditors may request the Chair of the Committee to consider any matters
which the internal or external auditors believe should be brought to the attention of the Committee or the Board.

**16.** **Separate Sessions** 

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) The Committee Chair shall meet periodically with the Chief Financial Officer, the lead internal auditor and
the external auditor in separate executive sessions to discuss any matters that the Committee or each of these groups believes should be discussed privately.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) The Chief Financial Officer, the lead internal auditor and the external auditor shall have access to the
Committee to bring forward matters requiring its attention.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c) The Committee shall meet periodically without Management present.

**17.** **Quorum** 

A majority of the 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.

*Emera Incorporated – 2022 Annual Information Form* *57*

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**20.** **Board Relationships and Reporting** 

The Committee shall:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) Review annually the Committee's Charter;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) Oversee the appropriate disclosure of the Committee's Charter as well as other information concerning
the Committee which is required to be disclosed by applicable legislation in Emera's Annual Information Form and any other applicable disclosure documents;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c) Report to the Board at the next following board meeting on any meeting held by the Committee, and as
required, regularly report to the Board on Committee activities, issues, and related recommendations; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(d) Maintain free and open communication between the Committee, the external auditors, internal auditors, and
Management, and determine that all parties are aware of their responsibilities.

**21.** **Powers** 

The Committee shall:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) examine and consider such other matters, and meet with such persons, in connection with the internal or
external audit of Emera's accounts, which the Committee in its discretion determines to be advisable;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b) have the authority to communicate directly with the internal and external auditors; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c) have the right to inspect all records of Emera or its affiliates and may elect to discuss such records, or
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 – 2022 Annual Information Form* *58*

## Exhibit 99.2

exhibit992p1i0

# Management's Discussion & Analysis

As at February 23, 2023

Management's Discussion & Analysis ('MD&A') provides a review of the results of operations of Emera Incorporated and its subsidiaries and investments during the fourth quarter of 2022 relative to the same quarter in 2021; for the full year of 2022 relative to 2021 and selected financial information for 2020; and its financial position as at December 31, 2022 relative to December 31, 2021. Throughout this discussion, 'Emera' and 'Company' refer to Emera Incorporated and all of its consolidated subsidiaries and investments. The Company's activities are carried out through five reportable segments: Florida Electric Utility, Canadian Electric Utilities, Gas Utilities and Infrastructure, Other Electric Utilities, and Other.

This discussion and analysis should be read in conjunction with the Emera annual audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2022. Emera follows United States Generally Accepted Accounting Principles ('USGAAP' or 'GAAP').

The accounting policies used by Emera's rate-regulated entities may differ from those used by Emera's non-rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities, revenues and expenses. At December 31, 2022, Emera's rate-regulated subsidiaries and investments include:

| Emera Rate-Regulated Subsidiary or Equity Investment | Accounting Policies Approved/Examined By |
| --- | --- |
| Subsidiary |  |
| Tampa Electric - Electric Division of Tampa Electric Company ('TEC') (1) | Florida Public Service Commission ('FPSC') and the Federal Energy Regulatory Commission ('FERC') |
| Nova Scotia Power Inc. ('NSPI') | Nova Scotia Utility and Review Board ('UARB') |
| Peoples Gas System ('PGS') - Gas Division of TEC (1) | FPSC |
| New Mexico Gas Company, Inc. ('NMGC') | New Mexico Public Regulation Commission ('NMPRC') |
| SeaCoast Gas Transmission, LLC ('SeaCoast') | FPSC |
| Emera Brunswick Pipeline Company Limited ('Brunswick Pipeline') | Canadian Energy Regulator ('CER') |
| Barbados Light & Power Company Limited ('BLPC') | Fair Trading Commission, Barbados ('FTC') |
| Grand Bahama Power Company Limited ('GBPC') | The Grand Bahama Port Authority ('GBPA') |
| Equity Investments |  |
| NSP Maritime Link Inc. ('NSPML') | UARB |
| Labrador Island Link Limited Partnership ('LIL') | Newfoundland and Labrador Board of Commissioners of Public Utilities ('NLPUB') |
| Maritimes & Northeast Pipeline Limited Partnership and Maritimes & Northeast Pipeline, LLC ('M&NP') | CER and FERC |
| St. Lucia Electricity Services Limited ('Lucelec') | National Utility Regulatory Commission ('NURC') |

(1) Effective January 1, 2023, Peoples Gas System ceased to be a division of TEC and the gas utility was reorganized, resulting in a separate legal entity called Peoples Gas System, Inc., a wholly-owned direct subsidiary of TECO Gas Operations, Inc.

All amounts are in Canadian dollars ('CAD'), except for the Florida Electric Utility, Gas Utilities and Infrastructure, and Other Electric Utilities sections of the MD&A, which are reported in United States dollar ('USD') unless otherwise stated.

Additional information related to Emera, including the Company's Annual Information Form, can be found on SEDAR at www.sedar.com.

1

## TABLE OF CONTENTS

| Forward-looking Information | 2 | Consolidated Cash Flow Highlights | 32 |
| --- | --- | --- | --- |
| Introduction and Strategic Overview | 3 | Working Capital | 33 |
| Non-GAAP Financial Measures and Ratios | 4 | Contractual Obligations | 34 |
| Consolidated Financial Review | 7 | Forecasted Gross Consolidated Capital |  |
| Significant Items Affecting Earnings | 7 | Expenditures | 34 |
| Consolidated Financial Highlights | 7 | Debt Management | 35 |
| Consolidated Income Statement Highlights | 9 | Credit Ratings | 37 |
| Business Overview and | 11 | Guaranteed Debt | 37 |
| Outlook |  | Outstanding Stock Data | 38 |
| Florida Electric Utility | 11 | Pension Funding | 39 |
| Canadian Electric Utilities | 12 | Off-Balance Sheet Arrangements | 39 |
| Gas Utilities and Infrastructure | 16 | Dividend Payout Ratio | 40 |
| Other Electric Utilities | 17 | Transactions with Related Parties | 40 |
| Other | 19 | Enterprise Risk and Risk Management | 41 |
| Consolidated Balance Sheet Highlights | 20 | Risk Management including Financial |  |
| Other Developments | 21 | Instruments | 54 |
| Financial Highlights | 22 | Disclosure and Internal Controls | 56 |
| Florida Electric Utility | 22 | Critical Accounting Estimates | 56 |
| Canadian Electric Utilities | 23 | Changes in Accounting Policies and | 62 |
| Gas Utilities and Infrastructure | 26 | Practices |  |
| Other Electric Utilities | 28 | Future Accounting Pronouncements | 62 |
| Other | 29 | Summary of Quarterly Results | 62 |
| Liquidity and Capital Resources | 31 |  |  |

## 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.

2

The forward-looking information is based on reasonable assumptions and is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors that could cause results or events to differ from current expectations include, without limitation: regulatory and political risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; liquidity and capital market risk; future dividend growth; timing and costs associated with certain capital investments; expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; maintenance of adequate insurance coverage; changes in customer energy usage patterns; developments in technology that could reduce demand for electricity; global climate change; weather; unanticipated maintenance and other expenditures; system operating and maintenance risk; derivative financial instruments and hedging; interest rate risk; inflation risk; counterparty risk; disruption of fuel supply; country risks; environmental risks; foreign exchange ('FX'); regulatory and government decisions, including changes to environmental, financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of service area; risk of failure of information technology ('IT') infrastructure and cybersecurity risks; uncertainties associated with infectious diseases, pandemics and similar public health threats, such as the COVID-19 novel coronavirus ('COVID-19') pandemic; market energy sales prices; labour relations; and availability of labour and management resources.

Readers are cautioned not to place undue reliance on forward-looking information, as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the forward-looking information. All forward-looking information in this MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, Emera undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise.

# INTRODUCTION AND STRATEGIC OVERVIEW

Based in Halifax, Nova Scotia, Emera owns and operates cost-of-service rate-regulated electric and gas utilities in Canada, the United States and the Caribbean. Cost-of-service utilities provide essential electric and gas services in designated territories under franchises and are overseen by regulatory authorities. Emera's strategic focus continues to be safely delivering cleaner, affordable and reliable energy to its customers.

The majority of Emera's investment in rate-regulated businesses are located in Florida with other investments in Nova Scotia, New Mexico and the Caribbean. Emera's portfolio of regulated utilities provides reliable earnings, cash flow and dividends. Earnings opportunities in regulated utilities are generally driven by the magnitude of net investment in the utility (known as 'rate base'), and the amount of equity in the capital structure and the return on that equity ('ROE') as approved through regulation. Earnings are also affected by sales volumes and operating expenses.

Emera's capital investment plan is $8 - 9 billion over the 2023-to-2025 period (including a $240 million equity investment in the LIL in 2023), mainly focused in Florida. This results in a forecasted rate base growth of approximately 7 per cent to 8 per cent through 2025. The capital investment plan continues to include significant investments across the portfolio in renewable and cleaner generation, reliability and integrity investments, infrastructure modernization, and customer-focused technologies. Emera's capital investment plan is being funded primarily through internally generated cash flows and debt raised at the operating company level. Equity requirements in support of the Company's capital investment plan are expected to be funded through the issuance of preferred equity and the issuance of common equity through Emera's dividend reinvestment plan ('DRIP') and at-the-market program ('ATM program'). Maintaining investment-grade credit ratings is a priority of the Company.

Emera has provided annual dividend growth guidance of four to five per cent through 2025. The Company targets a long-term dividend payout ratio of adjusted net income of 70 to 75 per cent and, while the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to return to that range over time. For further information on the non-GAAP measure 'Dividend Payout Ratio of Adjusted Net Income', refer to the 'Non-GAAP Financial Measures and Ratios' section.

3

Seasonal patterns and other weather events affect demand and operating costs. Similarly, mark-to-market adjustments and foreign currency exchange can have a material impact on financial results for a specific period. Emera's consolidated net income and cash flows are impacted by movements in the USD relative to the Canadian dollar. Emera may hedge both transactional and translational exposure. These impacts, as well as the timing of capital investments and other factors, mean results in any one quarter are not necessarily indicative of results in any other quarter, or for the year as a whole.

Energy markets worldwide are facing significant change and Emera is well positioned to respond to shifting customer demands, digitization, decarbonization, complex regulatory environments, and decentralized generation.

Customers are looking for more choice, better control, and enhanced reliability in a time where costs of decentralized generation and storage have become more competitive in some regions. Advancing technologies are transforming the way utilities interact with their customers and generate and transmit energy. In addition, climate change and extreme weather are shaping how utilities operate and how they invest in infrastructure. There is also an overall need to replace aging infrastructure and further enhance reliability. Emera will play a role in all of these trends. Emera's strategy is to fund investments in renewable energy and technology assets which protect the environment and benefit customers through fuel or operating cost savings.

For example, significant investments to facilitate the use of renewable and low-carbon energy include the Maritime Link in Atlantic Canada, and the ongoing construction of solar generation and modernization of the Big Bend Power Station at Tampa Electric. Emera's utilities are also investing in reliability projects and replacing aging infrastructure. All of these projects demonstrate Emera's strategy of safely delivering cleaner, reliable, and affordable energy for its customers.

Building on its decarbonization progress, Emera is continuing its efforts by establishing clear carbon reduction goals and a vision to achieve net-zero carbon dioxide emissions by 2050.

This vision is inspired by Emera's strong track record, the Company's experienced team, and a clear path to Emera's interim carbon goals. With existing technologies and resources, and subject to supportive government and regulatory decisions, Emera is working to achieve the following goals compared to corresponding 2005 levels:

- A 55 per cent reduction in carbon dioxide emissions by 2025.
- The retirement of Emera's last existing coal unit no later than 2040.
- An 80 per cent reduction in carbon dioxide emissions by 2040.

Achieving the above climate goals on these timelines is subject to the Company's regulatory obligations and other external factors beyond Emera's control.

Emera seeks to deliver on its Climate Commitment while maintaining its focus on investing in reliability and staying focused on the cost impacts for customers. Emera is also committed to identifying emerging technologies and continuing to work constructively with policymakers, regulators, partners, investors and customers to achieve these goals and realize its net-zero vision.

Emera is committed to world-class safety, operational excellence, good governance, excellent customer service, reliability, being an employer of choice, and building constructive relationships.

## NON-GAAP FINANCIAL MEASURES AND RATIOS

Emera uses financial measures and ratios that do not have standardized meaning under USGAAP and may not be comparable to similar measures presented by other entities. Emera calculates the non-GAAP measures and ratios by adjusting certain GAAP measures for specific items. Management believes excluding these items better distinguishes the ongoing operations of the business and allows investors to better understand and evaluate the business. These measures and ratios are discussed and reconciled below.

4

### Adjusted Net Income Attributable to Common Shareholders, Adjusted Earnings (Loss) Per Common Share (“EPS”) - Basic and Dividend Payout Ratio of Adjusted Net Income

Emera calculates an adjusted net income attributable to common shareholders (“adjusted net income”) measure by excluding the effect of mark-to-market (“MTM”) adjustments, impairment charges, the impact of the NSPML unrecoverable costs, and the 2020 gain on sale of Emera Maine.

Management believes excluding from net income the effect of these MTM valuations and changes thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows, and therefore excludes these MTM adjustments for evaluation of performance and incentive compensation. The MTM adjustments are related to the following:

- held-for-trading (“HFT”) commodity derivative instruments, including adjustments related to the price differential between the point where natural gas is sourced and where it is delivered, and the related amortization of transportation capacity recognized as a result of certain Emera Energy marketing and trading transactions;
- the business activities of Bear Swamp Power Company LLC (“Bear Swamp”) included in Emera’s equity income;
- equity securities held in BLPC and a captive reinsurance company in the Other segment; and
- FX hedges entered into to hedge USD denominated operating unit earnings exposure.

For further detail on MTM adjustments, refer to the “Consolidated Financial Review”, “Financial Highlights - Other Electric Utilities”, and “Financial Highlights - Other” sections.

In Q4 2022, the Company recognized a $73 million non-cash goodwill impairment charge related to GBPC due to a decline in the fair value of the reporting unit. The fair value decline was driven by the effects of macro-economic factors on the discount rate calculation, including the risk-free rate assumption. Management believes excluding from net income the effect of this charge better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the Company. For further details on this GBPC impairment charge, refer to “Significant Items Impacting Earnings”, and “Financial Highlights - Other” sections.

In February 2022, the UARB issued a decision to disallow the recovery of $9 million in costs ($7 million after-tax) included in NSPML’s final capital cost application. The after-tax unrecoverable costs were recognized in “Income from equity investments” in Emera’s Consolidated Statements of Income. Management believes excluding these unrecoverable costs from the calculation of adjusted net income better reflects the underlying operations in the period. For further details on the NSPML unrecoverable costs, refer to the “Business Overview and Outlook - Canadian Electric Utilities” and “Financial Highlights - Canadian Electric Utilities” sections.

In 2020, the Company recognized a gain on the sale of Emera Maine and certain non-cash impairment charges. Management believes excluding these from net income better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the business.

Adjusted EPS - basic and dividend payout ratio of adjusted net income are non-GAAP ratios which are calculated using adjusted net income, as described above. For further details on dividend payout ratio of adjusted net income, see the “Dividend Payout Ratio” section.

Emera calculates adjusted net income for the Canadian Electric Utilities, Other Electric Utilities, and Other segments. Reconciliation to the nearest GAAP measure is included in each segment. Refer to “Financial Highlights - Canadian Electric Utilities”, “Financial Highlights - Other Electric Utilities” and “Financial Highlights - Other” sections.

5

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

| For the millions of dollars (except per share amounts) | Three months ended December 31 |  | Year ended December 31 |  |  |
| --- | --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 | 2020 |
| Net income attributable to common shareholders | $483 | $324 | $945 | $510 | $938 |
| MTM gain (loss), after-tax (1) | 307 | 156 | 175 | (213) | (10) |
| Impairment charges, after-tax (2) | (73) | - | (73) | - | (26) |
| NSPML unrecoverable costs (3) | - | - | (7) | - | - |
| Gain on sale, after tax and transaction costs (4) | - | - | - | - | 309 |
| Adjusted net income attributable to common shareholders | $249 | $168 | $850 | $723 | $665 |
| EPS - basic | $1.80 | $1.24 | $3.56 | $1.98 | $3.78 |
| Adjusted EPS - basic | $0.93 | $0.64 | $3.20 | $2.81 | $2.68 |

(1) Net of income tax expense of $124 million for the three months ended December 31, 2022 (2021 - $63 million expense) and $73 million expense for the year ended December 31, 2022 (2021 - $86 million recovery) (2020 - $8 million recovery).

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

(3) Emera accounts for NSPML as an equity investment and therefore the after-tax unrecoverable costs were recorded in 'Income from equity investments' on Emera's Consolidated Statements of Income.

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

## EBITDA and Adjusted EBITDA

Earnings before interest, income taxes, depreciation and amortization ('EBITDA') and adjusted EBITDA are non-GAAP financial measures used by Emera. These financial measures are used by numerous investors and lenders to better understand cash flows and credit quality. EBITDA is useful to assess Emera's operating performance and indicates the Company's ability to service or incur debt, invest in capital, and finance working capital requirements.

Similar to adjusted net income calculations described above, adjusted EBITDA represents EBITDA absent the income effect of MTM adjustments, impairment charges, the NSPML unrecoverable costs, and the 2020 gain on sale of Emera Maine.

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

| For the millions of dollars | Three months ended December 31 |  | Year ended December 31 |  |  |
| --- | --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 | 2020 |
| Net income (1) | $499 | $338 | $1,009 | $561 | $984 |
| Interest expense, net | 206 | 151 | 709 | 611 | 679 |
| Income tax expense (recovery) | 154 | 85 | 185 | (6) | 341 |
| Depreciation and amortization | 254 | 227 | 952 | 902 | 881 |
| EBITDA | $1,113 | $801 | $2,855 | $2,068 | $2,885 |
| MTM gain (loss), excluding income tax | 431 | 219 | 248 | (299) | (18) |
| Impairment charges, excluding income tax | (73) | - | (73) | - | (25) |
| NSPML unrecoverable costs (2) | - | - | (7) | - | - |
| Gain on sale, net of transaction costs (excluding income tax) | - | - | - | - | 585 |
| Adjusted EBITDA | $755 | $582 | $2,687 | $2,367 | $2,343 |

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

(2) Emera accounts for NSPML as an equity investment and therefore the after-tax unrecoverable costs were recorded in 'Income from equity investments' on Emera's Consolidated Statements of Income.

6

# CONSOLIDATED FINANCIAL REVIEW

## Significant Items Affecting Earnings

### GBPC Impairment Charge

In Q4 2022, Emera recognized a goodwill impairment charge of $73 million ($0.27 per common share) for GBPC due to a decline in the fair value of the reporting unit. Although the cash flows of GBPC have not changed significantly compared to previous periods, the decline in the fair value was driven by the effects of macro-economic factors on discount rate calculations, including the risk-free rate assumption. This non-cash charge was recorded in “Impairment charge” on the Consolidated Statements of Income and reduced the GBPC goodwill balance to nil. For further details, refer to note 22 in the consolidated financial statements.

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

On December 15, 2022, a payment of $63 million ($45 million after tax and legal costs, or $0.17 per common share), was made by the Republic of Guatemala to TECO Energy in satisfaction of the second and final award issued by the International Centre of the Settlement of Investment Disputes tribunal regarding a dispute over an investment of TGH, a wholly owned subsidiary of TECO Energy. The dispute related to the 2007 intervention by the government of Guatemala in an ongoing independent rate-setting process to unilaterally set a new and lower tariff. The payment was recognized in “Other income, net” on the Consolidated Statements of Income. For further details, refer to note 27 in the consolidated financial statements.

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

MTM gain, after-tax increased $151 million to $307 million in Q4 2022, compared to $156 million in Q4 2021, and for the year ended December 31, increased $388 million to $175 million compared to a MTM loss, after-tax of $213 million for the same period in 2021. These increases were due to changes in existing positions and reversal of losses in 2022, partially offset by higher amortization in 2022 of gas transportation assets at Emera Energy.

## Consolidated Financial Highlights

| For the millions of dollars | Three months ended December 31 |  | Year ended December 31 |  |
| --- | --- | --- | --- | --- |
| Adjusted net income | 2022 | 2021 | 2022 | 2021 |
|  |  |  |  | 2020 |
| Florida Electric Utility | $124 | $85 | $596 | $462 |
| Canadian Electric Utilities | 46 | 67 | 222 | 241 |
| Gas Utilities and Infrastructure | 72 | 55 | 221 | 198 |
| Other Electric Utilities | 8 | 5 | 29 | 20 |
| Other | (1) | (44) | (218) | (198) |
| Adjusted net income | $249 | $168 | $850 | $723 |
| MTM gain (loss), after-tax | 307 | 156 | 175 | (213) |
| Impairment charges, after-tax | (73) | - | (73) | - |
| NSPML unrecoverable costs | - | - | (7) | - |
| Gain on sale, after tax and transaction costs | - | - | - | - |
| Net income attributable to common shareholders | $483 | $324 | $945 | $510 |
|  |  |  |  | $938 |

7

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

| For the millions of dollars | Three months ended December 31 | Year ended December 31 |
| --- | --- | --- |
| Adjusted net income - 2021 | $168 | $723 |
| Operating Unit Performance |  |  |
| Increased earnings at Tampa Electric due to higher revenues as a result of rate increases effective January 2022, customer growth, and the impact of a weakening CAD. These were partially offset by higher operating, maintenance and general expenses (OM&G'), increased interest expense, and higher depreciation. Year-over-year also increased due to favourable weather | 39 | 134 |
| Increased earnings at Emera Energy Services ('EES') due to favourable market conditions | 21 | 21 |
| Increased earnings at PGS due to higher off-system sales and customer growth, partially offset by higher OM&G. Year-over-year also increased due to reversal of accumulated depreciation as a result of the rate case settlement | 2 | 10 |
| Increased earnings at Seacoast due to commencement of a 34-year pipeline lateral lease in 2022 | 2 | 9 |
| Increased earnings at NMGC were primarily due to higher asset optimization revenues. Year-over-year increased earnings were partially offset by higher OM&G and increased depreciation | 11 | 4 |
| Decreased earnings at NSPI due to higher OM&G primarily due to increased costs for storm restoration, IT, power generation, regulatory affairs, and higher depreciation. This was partially offset by higher sales volumes. Quarter-over-quarter also decreased due to unfavourable weather | (20) | (10) |
| Corporate |  |  |
| TGH award, after tax and legal costs, in Q4 2022. Refer to the 'Significant Items Affecting Earnings' section | 45 | 45 |
| Increased income tax recovery primarily due to increased losses before provision for income taxes | 17 | 34 |
| Increased OM&G, pre-tax, due to the timing of long-term compensation and related hedges | (19) | (55) |
| Increased FX loss, pre-tax, primarily due to realized gains in 2021 on FX hedges entered into to hedge USD denominated operating unit earnings exposure | (9) | (28) |
| Increased interest expense, pre-tax, due to higher interest rates and increased total debt | (17) | (27) |
| Increased preferred stock dividends due to issuance of preferred shares in 2021 | (2) | (13) |
| Other Variances | 11 | 3 |
| Adjusted net income - 2022 | $249 | $850 |

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

8

| For the millions of dollars | 2022 | Year ended December 31 2021 | 2020 |
| --- | --- | --- | --- |
| Operating cash flow before changes in working capital | $1,147 | $1,337 | $1,420 |
| Change in working capital | (234) | (152) | 217 |
| Operating cash flow | $913 | $1,185 | $1,637 |
| Investing cash flow | $(2,569) | $(2,332) | $(1,224) |
| Financing cash flow | $1,555 | $1,311 | $(372) |

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

| As at millions of dollars | 2022 | 2021 | December 31 2020 |
| --- | --- | --- | --- |
| Total assets | $39,742 | $34,244 | $31,234 |
| Total long-term debt (including current portion) | $16,318 | $14,658 | $13,721 |

## Consolidated Income Statement Highlights

| For the millions of dollars (except per share amounts) | Three months ended December 31 |  |  | Year ended December 31 |  |  | Year ended December 31 |  |
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
|  | 2022 | 2021 | Variance | 2022 | 2021 | Variance | 2022 | 2021 |
| Operating revenues | $2,358 | $1,868 | $490 | $7,588 | $5,765 | $1,823 | $5,506 | $5,506 |
| Operating expenses | 1,638 | 1,352 | (286) | 5,959 | 4,835 | (1,124) | 4,359 | 4,359 |
| Income from operations | $720 | $516 | $204 | $1,629 | $930 | $699 | $1,147 | $1,147 |
| Net income attributable to common shareholders | $483 | $324 | $159 | $945 | $510 | $435 | $938 | $938 |
| Adjusted net income | $249 | $168 | $81 | $850 | $723 | $127 | $665 | $665 |
| Weighted average shares of common stock outstanding (in millions) (1) | 269.0 | 260.8 | 8.2 | 265.5 | 257.2 | 8.3 | 247.8 | 247.8 |
| EPS - basic | $1.80 | $1.24 | $0.56 | $3.56 | $1.98 | $1.58 | $3.78 | $3.78 |
| EPS - diluted | $1.80 | $1.20 | $0.60 | $3.55 | $1.98 | $1.57 | $3.78 | $3.78 |
| Adjusted EPS - basic | $0.93 | $0.64 | $0.29 | $3.20 | $2.81 | $0.39 | $2.68 | $2.68 |
| Adjusted EBITDA | $755 | $582 | $173 | $2,687 | $2,367 | $320 | $2,343 | $2,343 |
| Dividends per common share declared | $0.6900 | $0.6625 | $0.0275 | $2.6775 | $2.5750 | $0.1025 | $2.4750 | $2.4750 |
| Dividends per first preferred shares declared: |  |  |  |  |  |  |  |  |
| Series A |  |  |  | $0.5456 | $0.5456 | $ - | $0.6155 | $ - |
| Series B |  |  |  | $0.6869 | $0.4873 | $0.1996 | $0.6965 | $ - |
| Series C |  |  |  | $1.1802 | $1.1802 | $ - | $1.1802 | $ - |
| Series E |  |  |  | $1.1250 | $1.1250 | $ - | $1.1250 | $ - |
| Series F |  |  |  | $1.0505 | $1.0505 | $ - | $1.0535 | $ - |
| Series H |  |  |  | $1.2250 | $1.2250 | $ - | $1.2250 | $ - |
| Series J |  |  |  | $1.0625 | $0.6470 | $0.4155 | $ - | $ - |
| Series L |  |  |  | $1.1500 | $0.1638 | $0.9862 | $ - | $ - |

(1) Effective February 10, 2022, deferred share units are no longer able to be settled in shares and are therefore excluded from weighted average shares of common stock outstanding.

### Operating Revenues

For Q4 2022, operating revenues increased $490 million compared to Q4 2021 and, absent increased MTM gains of $195 million, increased $295 million. For the year ended December 31, 2022, operating revenues increased $1,823 million compared to 2021 and, absent increased MTM gains of $555 million, increased by $1,268 million. The increases in both periods were due to: higher fuel revenues at NMGC, Tampa Electric PGS and BLPC; new rates effective January 2022 and customer growth at Tampa Electric; the impact of a weaker CAD; higher off-system sales and customer growth at PGS; and increased marketing and trading margin due to favourable market conditions at EES. Year-over-year also increased due to increased sales volumes at NSPI and favourable weather at Tampa Electric.

9

## **Operating Expenses**

For Q4 2022, operating expenses increased $286 million compared to Q4 2021 and, absent the GBPC impairment charge of $73 million, increased by $213 million. For the year ended December 31, 2022, operating expenses increased $1,124 million compared to 2021 and, absent the GBPC impairment charge of $73 million, increased by $1,051 million. The increases in both periods were due to: higher natural gas prices at NMGC and PGS; the impact of a weaker CAD; and increased OM&G at Tampa Electric, Corporate, NSPI, NMGC and PGS. Year-over-year also increased due to higher natural gas and fuel prices at Tampa Electric and BLPC.

## **Other Income, Net**

Other income, net increased for Q4 2022 and the year ended December 31, 2022, compared to the same periods in 2021, primarily due to the TGH award in Q4 2022.

## **Net Income and Adjusted Net Income**

Net income attributable to common shareholders for Q4 2022, as compared to Q4 2021, was favourably impacted by the $151 million increase in MTM gains, after-tax and unfavourably impacted by the $73 million GBPC impairment charge. Absent these changes, adjusted net income increased $81 million. The increase was primarily due to: the TGH award in Q4 2022; higher earnings contribution from Tampa Electric, Emera Energy and NMGC; and the impact of a weaker CAD. These were partially offset by lower earnings contribution from NSPI and increased corporate OM&G due to the timing of long-term compensation and related hedges, and higher corporate interest expense.

Net income attributable to common shareholders for the year ended 2022, as compared to the same period in 2021, was favourably impacted by the $388 million increase in MTM gains, after-tax and unfavourably impacted by the $73 million GBPC impairment charge as well as the $7 million in NSPML unrecoverable costs. Absent these changes, adjusted net income increased $127 million. The increase was primarily due to: higher earnings contributions from Tampa Electric, Emera Energy, PGS and Seacoast; the TGH award in Q4 2022; and the impact of a weaker CAD. These were partially offset by increased corporate OM&G due to the timing of long-term compensation and related hedges, higher corporate interest expense, realized gains on corporate FX hedges in 2021, increased preferred stock dividends and lower earnings contribution from NSPI.

## **EPS and Adjusted EPS - Basic**

EPS and Adjusted EPS - basic were higher for Q4 2022, and for the year ended December 31, 2022, due to the impact of higher earnings as discussed above, partially offset by the impact of the increase in weighted average shares of common stock outstanding.

## **Effect of Foreign Currency Translation**

Emera operates in Canada, the United States and various Caribbean countries and, as such, generates revenues and incurs expenses denominated in local currencies which are translated into CAD for financial reporting. Changes in translation rates, particularly in the value of the USD against the CAD, can positively or adversely affect results.

In general, Emera's earnings benefit from a weakening CAD and are adversely impacted by a strengthening CAD. The impact in any period is driven by rate changes, the timing and percentage of earnings from foreign operations, and the impact of FX hedges entered into to hedge USD denominated operating unit earnings exposure.

10

Results of foreign operations are translated at the weighted average rate of exchange, and assets and liabilities of foreign operations are translated at period end rates. The relevant CAD/USD exchange rates for 2022 and 2021 are as follows:

|  | Three months ended December 31 |  | Year ended December 31 |  |
| --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 |
| Weighted average CAD/USD | $1.37 | $1.26 | $1.34 | $1.26 |
| Period end CAD/USD exchange rate | $1.35 | $1.27 | $1.35 | $1.27 |

The table below includes Emera's significant segments whose contributions to adjusted net income are recorded in USD currency.

| For the millions of USD | Three months ended December 31 |  | Year ended December 31 |  |
| --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 |
| Florida Electric Utility | $91 | $67 | $458 | $369 |
| Other Electric Utilities | 7 | 4 | 23 | 16 |
| Gas Utilities and Infrastructure (1) | 45 | 37 | 143 | 130 |
| Other segment (2) | 30 | (20) | (50) | (98) |
| Total (3) | $173 | $88 | $574 | $417 |

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

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

(3) Excludes $222 million USD in MTM gain, after-tax, for the three months ended December 31, 2022 (2021 - $122 million USD MTM gain, after-tax) and MTM gain, after-tax of $130 million USD for the year ended December 31, 2022 (2021 - $164 million USD MTM loss, after-tax) and the GBPQ impairment charge of $54 million USD for the three months and year ended December 31, 2022 (2021 - nil).

The impact of the weakening CAD, partially offset by the unrealized losses on FX hedges increased net income by $42 million in Q4 2022 and $30 million for the year ended December 31, 2022, compared to the same periods in 2021. Weakening of the CAD increased adjusted net income by $14 million in Q4 2022 and $28 million for the year ended December 31, 2022, compared to the same periods in 2021. Impacts of the weakening CAD include the impacts of corporate FX hedges in the Other segment.

## BUSINESS OVERVIEW AND OUTLOOK

### Florida Electric Utility

Florida Electric Utility consists of Tampa Electric, a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity, serving customers in West Central Florida. Tampa Electric has $12.1 billion USD of assets and approximately 827,000 customers at December 31, 2022. Tampa Electric owns 6,549 megawatts ('MW') of generating capacity, of which 78 per cent is natural gas-fired, 15 per cent is solar and 7 per cent is coal. Tampa Electric owns 2,171 kilometres of transmission facilities and 19,916 kilometres of distribution facilities. Tampa Electric meets the planning criteria for reserve capacity established by the FPSC, which is a 20 per cent reserve margin over firm peak demand.

Tampa Electric's approved regulated ROE range is 9.25 per cent to 11.25 per cent, based on an allowed equity capital structure of 54 per cent. An ROE of 10.20 per cent will be used for the calculation of the return on investments for clauses.

Tampa Electric anticipates earning within its ROE range in 2023. New base rates effective January 1, 2023, as a result of the 2021 settlement agreement, will result in higher 2023 USD earnings than in 2022. Normalizing 2022 for weather, Tampa Electric sales volumes in 2023 are projected to be higher than in 2022 due to customer growth. Tampa Electric expects customer growth rates in 2023 to be comparable to 2022, reflective of the current expected economic growth in Florida.

11

On January 23, 2023, Tampa Electric requested an adjustment to its fuel charges to recover the 2022 fuel under-recovery of $518 million USD over a period of 21 months. The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $170 million USD for the balance of 2023. The proposed changes will be decided by the FPSC in March 2023, and recovery is expected to begin in April 2023.

On September 28, 2022, Hurricane Ian made landfall in Southwest Florida as a Category 4 hurricane and, as a result, approximately 291,000 customers lost power. The majority of Hurricane Ian restoration costs were charged against Tampa Electric's FPSC approved storm reserve, resulting in minimal impact to earnings for 2022. The total cost of restoration was $126 million USD, with approximately $119 million USD charged to the storm reserve. Total restoration costs charged to the storm reserve have exceeded the reserve balance and have been deferred as a regulatory asset for future recovery. On January 23, 2023, Tampa Electric petitioned the FPSC for recovery of the storm reserve regulatory asset and the replenishment of the balance in the reserve to the previous approved reserve level of $56 million USD, for a total of approximately $131 million USD. The proposed changes will be decided by the FPSC in March 2023, and recovery is expected to begin in April 2023 through March 2024.

The mid-course fuel adjustment requested by Tampa Electric on January 19, 2022, was approved on March 1, 2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel and capacity costs of $169 million USD and was spread over customer bills from April 1, 2022 through December 2022.

In 2023, capital investment in the Florida Electric Utility segment is expected to be $1.3 billion USD (2022 - $1.1 billion USD), including allowance for funds used during construction ('AFUDC'). Capital projects include solar investments, grid modernization and storm hardening investments.

## Canadian Electric Utilities

Canadian Electric Utilities includes NSPI and ENL. NSPI is a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity and the primary electricity supplier to customers in Nova Scotia. ENL is a holding company with equity investments in NSPML and LIL: two transmission investments related to the development of an 824 MW hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador.

### NSPI

With $6.8 billion of assets and approximately 541,000 customers, NSPI owns 2,420 MW of generating capacity, of which approximately 44 per cent is coal-fired; 28 per cent is natural gas and/or oil; 19 per cent is hydro and wind; 7 per cent is petcoke and 2 per cent is biomass-fueled generation. In addition, NSPI has contracts to purchase renewable energy from independent power producers ('IPPs'), which own 546 MW of capacity. NSPI also has rights to 153 MW of Maritime Link capacity, representing Nalcor Energy's ('Nalcor') Nova Scotia Block ('NS Block') delivery obligations, as discussed below. NSPI owns approximately 5,000 kilometres of transmission facilities and 28,000 kilometres of distribution facilities.

NSPI's approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 40 per cent of approved rate base.

NSPI anticipates earning near the low end of its allowed ROE range in 2023, and below the allowed range in 2024. NSPI expects earnings and sales volumes to be higher in 2023 than 2022.

NSPI operated under a three-year fuel stability plan which resulted in an average annual overall rate increase of 1.5 per cent to recover fuel costs for the period of 2020 through 2022. These rates include recovery of Maritime Link costs (discussed below in the 'ENL, NSPML' section).

12

On November 9, 2022, the Nova Scotia provincial government enacted Bill 212, “Public Utilities Act (amended)”. The legislation limits non-fuel rate increases in NSPI’s 2022 General Rate Application (“GRA”) to the UARB, excluding increases relating to demand side management (“DSM”) costs, to a total of 1.8 per cent between the effective date of the UARB’s decision and the end of 2024. The legislation also:

- requires revenue generated from the non-fuel rate increase to be used only to improve the reliability of service to ratepayers,
- limits NSPI’s return on equity to 9.25 per cent and equity ratio to 40 per cent, and
- limits the rate used to accrue interest on regulatory deferrals to the Bank of Canada policy interest rate plus 1.75 per cent, unless otherwise directed by the UARB.

Actions required to address the impact of Bill 212, “Public Utilities Act (amended)”, include a material reduction in NSPI’s planned capital investments and operating costs over the 2023 through 2024 period. Such deferral of capital investment and operating costs may result in higher customer costs in future periods. The legislation will have a direct and negative impact on the financial performance of NSPI and has had a negative impact on NSPI’s credit quality. For more information on this risk, refer to the “Risk Management and Financial Instruments - Regulatory and Political Risk” section.

On November 24, 2022, NSPI filed with the UARB a comprehensive settlement agreement between NSPI, key customer representatives and participating interest groups (“NSPI Settlement Agreement”) in relation to its GRA filed in January 2022. The NSPI Settlement Agreement was structured to be consistent with the amendments to the Public Utilities Act made under Bill 212, which included a 1.8 per cent cap on non-fuel rate increases for 2023 and 2024. Bill 212, “Public Utilities Act (amended),” is described further above. The NSPI Settlement Agreement also addresses the recovery of fuel costs over the settlement period and establishes a DSM rider. This will result in a combined fuel and non-fuel rate increase of 6.9 per cent each year for 2023 and 2024 and annualized incremental revenue (fuel and non-fuel) of $105 million in 2023 and $115 million in 2024. In addition, any under or over recovery of fuel costs will be addressed through the UARB’s established FAM process. NSPI’s ROE range will continue to be 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 40 per cent. The NSPI Settlement Agreement also establishes a storm rider for each of 2023, 2024 and 2025, which gives NSPI the option to apply to the UARB for recovery of costs if major storm restoration expense exceeds approximately $10 million in a given year. On February 2, 2023, NSPI received the UARB’s decision, which substantially approved the NSPI Settlement Agreement as filed. Approved rate increases will be effective as of the date of the decision.

On September 24, 2022, Nova Scotia was struck by Hurricane Fiona, which made landfall as a post-tropical storm equivalent to a Category 2 hurricane. The storm had sustained winds of over 100 kilometres per hour and peak gusts of approximately 180 kilometres per hour. This historic storm for Nova Scotia caused significant and widespread damage to NSPI’s transmission and distribution system and at the height of the storm approximately 415,000 customers lost power. The total cost of the restoration was approximately $115 million, of which $91 million was capitalized to Property, plant and equipment (“PP&E”) and $24 million deferred to Other long-term assets for future amortization, subject to UARB approval. NSPI intends to submit an application to the UARB requesting to defer the recognition of incremental operating costs related to storm restoration. If the deferral is approved, this balance will be reclassified to “Regulatory assets” and amortized over the UARB approved recognition period.

13

Energy from renewable sources has increased with Nalcor's NS Block delivery obligations from the Muskrat Falls hydroelectric project ('Muskrat Falls') commencing in 2021. Nalcor is obligated to provide NSPI with approximately 900 GWh of energy annually over 35 years. In addition, for the first five years of the NS Block, Nalcor is obligated to provide approximately 240 GWh of additional energy from the Supplemental Energy Block transmitted through the Maritime Link. Nalcor's final commissioning of the LIL has experienced delays and it's expected that final commissioning of the LIL will be completed in 2023. During these final stages of commissioning, there will be interruptions in supply, with any resultant delivery shortfalls being delivered on a timely basis in accordance with the Energy and Capacity Agreement. NSPI has the option of purchasing additional market-priced energy from Nalcor through the Energy Access Agreement. The Energy Access Agreement enables NSPI to access a market-priced bid from Nalcor for up to 1.8 Terawatt hours ('TWh') of energy in any given year and, on average, 1.2 TWh of energy per year through August 31, 2041.

Capital investment for 2023, including AFUDC, is expected to be approximately $375 million (2022 - $540 million). NSPI is primarily investing in capital projects required to support power system reliability and reliable service for customers.

### ***Environmental Legislation and Regulations***

NSPI is subject to environmental laws and regulations set by both the Government of Canada and the Province of Nova Scotia. NSPI continues to work with both levels of government to comply with these laws and regulations to maximize efficiency of emission control measures and minimize customer cost. NSPI anticipates that costs prudently incurred to achieve legislated compliance will be recoverable under NSPI's regulatory framework. NSPI faces risks associated with achieving climate-related and environmental legislative requirements, including the risk of non-compliance, which could adversely affect NSPI's operations and financial performance. For further discussion on these risks and environmental legislation and regulations, refer to the 'Enterprise Risk and Risk Management' section. Recent developments related to provincial and federal environmental laws and regulations are outlined below.

#### ***Nova Scotia Cap-and-Trade Program Regulations:***

NSPI is a participant in the Nova Scotia Cap-and-Trade Program ('Cap-and-Trade Program') and is subject to the 2019 through 2022 compliance period. NSPI received granted emissions allowances under the Cap-and-Trade Program and is permitted to purchase up to five per cent of the credits available at provincial auctions. Any remaining allowance shortfall requires the purchase of reserve credits directly from the provincial government, which are anticipated to be priced at a premium to provincial auction pricing. Compliance is forecast to be achieved through granted emissions allowances and credit purchases under the Cap-and-Trade Program, including reserve credits. Lower than forecast Muskrat Falls energy received during the compliance period has resulted in the increased deployment of higher carbon-emitting generation sources. The Province of Nova Scotia has agreed to provide approximately $165 million of relief from the 2019 through 2022 compliance costs, which was equal to the total cost of compliance forecast at the time of the fuel update submitted by NSPI to the UARB in September 2022 as part of the GRA. Discussions related to the final amount of relief and how this relief will be provided are ongoing. Further, NSPI's regulatory framework provides for the recovery of costs prudently incurred to comply with the Cap-and-Trade Program Regulations pursuant to NSPI's FAM.

14

#### *Carbon Pricing Regulations:*

On November 9, 2022, the Nova Scotia provincial government enacted Bill 208, 'Environment Act (amended)'. The legislation provides the framework for Nova Scotia's system to comply with the federal government's 2023 through 2030 carbon pollution pricing regulations laid out in the Pan-Canadian Framework on Clean Growth and Climate Change. Nova Scotia's proposed system utilizes an output-based pricing system that will implement performance standards for large industrial greenhouse gas emitters to achieve emission reduction goals. Subsequent regulations will be required to detail how the pricing system will operate. The Province of Nova Scotia's proposed output-based pricing system is subject to the approval of the federal government. If an agreement is not reached between the federal and provincial governments on a Nova Scotia system that meets the federal compliance criteria, Nova Scotia will be subject to the federal carbon pollution pricing backstop which uses emissions performances standards that vary by fuel type, and a carbon price that will start at $65 per tonne in 2023 and increase by $15 per tonne annually, reaching $170 per tonne by 2030. NSPI's regulatory framework provides for the recovery of costs prudently incurred to comply with carbon pricing programs pursuant to NSPI's FAM.

#### *Nova Scotia Renewable Energy Regulations:*

Under the provincially legislated Renewable Energy Regulations, 40 per cent of electric sales must be generated from renewable sources. This standard was predicated on receipt of the full NS Block. Due to the delay of the NS Block, the provincial government provided NSPI with an alternative compliance plan that requires NSPI to achieve 40 per cent of electric sales generated from renewable sources over the 2020 through 2022 period. With delivery of the NS Block commencing later than anticipated, as well as further interruptions in supply due to delays in the LIL, NSPI did not achieve the requirements of the alternative compliance plan. The Renewable Energy Regulations require NSPI to have acted in a duly diligent manner. If NSPI is found not to have acted in a duly diligent manner, it could be subject to a maximum penalty of $10 million.

### **ENL**

Total equity earnings from NSPML and LIL are expected to be higher in 2023, compared to 2022. Both the NSPML and LIL investments are recorded as 'Investments subject to significant influence' on Emera's Consolidated Balance Sheets.

#### *NSPML*

Equity earnings from the Maritime Link are dependent on the approved ROE and operational performance of NSPML. NSPML's approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 30 per cent.

The Maritime Link assets entered service on January 15, 2018, enabling the transmission of energy between Newfoundland and Nova Scotia, improved reliability and ancillary benefits, supporting the efficiency and reliability of energy in both provinces. Nalcor continues to advance towards completion of the LIL, and it's expected final commissioning will be achieved in 2023. Nalcor's NS Block delivery obligations commenced on August 15, 2021, and the NS Block will be delivered over the next 35 years pursuant to the project agreements. As Nalcor is in the final stages of commissioning the LIL, there will be commissioning related interruptions in supply with any resultant delivery shortfalls being delivered on a timely basis in accordance with the Energy and Capacity Agreement.

In February 2022, the UARB issued its decision and Board Order approving NSPML's requested rate base of approximately $1.8 billion less $9 million of costs ($7 million after-tax) that would not have otherwise been recoverable if incurred by NSPI. NSPML also received approval to collect up to $168 million (2021 - $172 million) from NSPI for the recovery of costs associated with the Maritime Link in 2022. This was subject to a holdback of up to $2 million per month, beginning April 2022, contingent on receiving at least 90 per cent of NS Block deliveries, including Supplemental Energy deliveries.

15

In December 2022, NSPML received UARB approval to collect up to $164 million from NSPI for the recovery of costs associated with the Maritime Link in 2023. This continues to be subject to a holdback of up to $2 million a month, as discussed above. On December 22, 2022, the UARB clarified its earlier direction regarding the holdback and NSPI can now release the holdback to NSPML when 90 per cent of NS Block deliveries, including Supplemental Energy deliveries, is achieved. This enabled NSPI to pay NSPML approximately $4 million of the 2022 holdback. As of December 31, 2022, an additional $14 million in aggregate has been held back by NSPI. Determination of allocation of the $14 million between NSPML and NSPI will be subject to a regulatory process that is expected to commence in early 2023 to review the holdback mechanism.

NSPML does not anticipate any significant capital investment in 2023.

#### *LIL*

ENL is a limited partner with Nalcor in LIL. Construction of the LIL is complete and Nalcor is forecasting it will achieve final commissioning in 2023.

Equity earnings from the LIL investment are based upon the book value of the equity investment and the approved ROE. Emera's current equity investment is $740 million, comprised of $410 million in equity contribution and $330 million of accumulated equity earnings. Emera's total equity contribution in the LIL, excluding accumulated equity earnings, is estimated to be approximately $650 million after the Lower Churchill projects are completed.

Cash earnings and return of equity will begin after commissioning of the LIL by Nalcor, which is anticipated in 2023, and until that point Emera will continue to record AFUDC earnings.

## Gas Utilities and Infrastructure

Gas Utilities and Infrastructure includes PGS, NMGC, SeaCoast, Brunswick Pipeline and Emera's non-consolidated investment in M&NP. PGS is a regulated gas distribution utility engaged in the purchase, distribution and sale of natural gas serving customers in Florida. NMGC is an intrastate regulated gas distribution utility engaged in the purchase, transmission, distribution and sale of natural gas serving customers in New Mexico. SeaCoast is a regulated intrastate natural gas transmission company offering services in Florida. Brunswick Pipeline is a regulated 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick, to markets in the northeastern United States.

### Peoples Gas System

With $2.5 billion USD of assets and approximately 468,000 customers, the PGS system includes 24,300 kilometres of natural gas mains and 13,500 kilometres of service lines. Natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) was 2 billion therms in 2022.

The approved ROE range for PGS is 8.9 per cent to 11.0 per cent, based on an allowed equity capital structure of 54.7 per cent. An ROE of 9.9 per cent is used for the calculation of return on investments for clauses.

### New Mexico Gas Company, Inc.

With $2.0 billion USD of assets and approximately 545,000 customers, NMGC's system includes approximately 2,426 kilometres of transmission pipelines and 17,781 kilometres of distribution pipelines. Annual natural gas throughput was approximately 926 million therms in 2022.

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

16

## Gas Utilities and Infrastructure Outlook

Gas Utilities and Infrastructure USD earnings are anticipated to be higher in 2023 than 2022, primarily due to a base rate increase at NMGC, effective January 2023.

PGS expects 2023 rate base growth and USD earnings to be consistent with 2022 as higher revenues from customer growth offset increased interest expenses and the effect of inflation. Increased residential and commercial sales volumes and customer growth are anticipated in 2023. PGS anticipates earning below its allowed ROE range in 2023 primarily due to rate base growth. As a result, on February 3, 2023, PGS notified the FPSC that it is planning to file a base rate proceeding in April 2023 for new rates effective January 2024.

The PGS rate case settlement, which was approved in November 2020, provides the ability to reverse a total of $34 million USD of accumulated depreciation through 2023. Through December 31, 2022, PGS reversed $14 million USD accumulated depreciation. The reversal of the remaining accumulated depreciation is expected to occur over 2023.

NMGC expects 2023 rate base and USD earnings to be higher in 2023 than 2022 due to base rate increases effective January 2023, as discussed below, and rate base growth to expand the distribution system and to continue to reliably serve customers. NMGC anticipates earning near its authorized ROE in 2023 and expects customer growth rates to be consistent with historical trends. NMGC's asset optimization revenues for 2022 were well above the historical average, and may not recur in 2023.

On December 13, 2021, NMGC filed a rate case with the NMPRC for new rates to become effective January 2023. On May 20, 2022, NMGC filed an unopposed settlement agreement with the NMPRC for an increase of $19 million USD in annual base revenues. The rates reflect the recovery of increased operating costs and capital investments in pipelines and related infrastructure. The NMPRC approved the settlement agreement on November 30, 2022.

In 2018, SeaCoast executed a 34-year agreement to provide long-term firm gas transportation service via a 21-mile, 30-inch pipeline lateral. The lease of the pipeline lateral commenced January 1, 2022.

In 2023, capital investment in the Gas Utilities and Infrastructure segment is expected to be approximately $475 million USD (2022 - $436 million USD), including AFUDC. PGS will make investments to expand its system and support customer growth. NMGC will continue to make investments to maintain the reliability of its system and support customer growth.

## Other Electric Utilities

Other Electric Utilities includes Emera (Caribbean) Incorporated ('ECI'), a holding company with regulated electric utilities. ECI's regulated utilities include vertically integrated regulated electric utilities of BLPC on the island of Barbados, GBPC on Grand Bahama Island, and a 19.5 per cent interest in Lucelec on the island of St. Lucia, which is accounted for on the equity basis.

On March 31, 2022, Emera completed the sale of its 51.9 per cent interest in Dominica Electricity Services Ltd. ('Domlec') for proceeds which approximated carrying value. Domlec was included in the Other Electric Utilities segment in Q1 2022. The sale did not have a material impact on earnings.

### BLPC

With $505 million USD of assets and approximately 133,000 customers, BLPC owns 276 MW of generating capacity, of which 96 per cent is oil-fired and four per cent is solar. BLPC owns approximately 188 kilometres of transmission facilities and 3,789 kilometres of distribution facilities. BLPC's approved regulated return on rate base for 2022 was 10 per cent.

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## GBPC

With $338 million USD of assets and approximately 19,000 customers, GBPC owns 98 MW of oil-fired generation, approximately 90 kilometres of transmission facilities and 670 kilometres of distribution facilities. GBPC's approved regulatory return on rate base for 2023 is 8.32 per cent (2022 - 8.23 per cent).

## Other Electric Utilities Outlook

Absent the impact of the GBPC impairment charge in Q4 2022, Other Electric Utilities' USD earnings in 2023 are expected to increase over the prior year primarily as a result of higher earnings due to higher base rates at BLPC.

BLPC currently operates pursuant to a franchise to generate, transmit and distribute electricity on the island of Barbados until 2028. In 2019, the Government of Barbados passed legislation amending the number of licenses required for the supply of electricity from a single integrated license which currently exists, to multiple licenses for Generation, Transmission and Distribution, Storage, Dispatch and Sales. In March 2021, BLPC reached commercial agreement with the Government of Barbados for each of the license types, subject to the passage of implementing legislation. The new licenses are expected to take effect in 2023 on completion of the legislative process. The Dispatch license will have a term of five years with the remaining licenses having terms ranging from 25-30 years. BLPC anticipates that any increased costs associated with the implementation of the new multi-licensed structure will be recoverable through BLPC's regulatory framework. BLPC is awaiting final enactment and will work towards implementation of the licenses once received.

On October 4, 2021 BLPC submitted a general rate review application to the FTC. The application seeks a rate adjustment and the implementation of a cost reflective rate structure that will facilitate the changes expected in the newly reformed electricity market and the country's transition toward 100 per cent renewable energy generation. The application seeks recovery of capital investment in plant, equipment and related infrastructure and results in an increase in annual non-fuel revenue of approximately $23 million USD upon approval. The application includes a request for an allowed regulatory ROE of 12.50 per cent on an allowed equity capital structure of 65 per cent. On September 16, 2022, the FTC granted BLPC interim rate relief, allowing an increase in base rates of approximately $3 million USD for the remainder of 2022 and approximately $1 million USD per month for 2023. Interim rate relief is effective from September 16, 2022 until the implementation of final rates. The hearing concluded in October 2022. On February 15, 2023, the FTC issued a decision on the BLPC rate review application which included the following significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent, a directive to update the major components of rate base to September 16, 2022, and a directive to establish regulatory liabilities of approximately $70 million USD related to the self-insurance fund, accumulated depreciation, and taxes. The impacts to BLPC's rate base and final rates are not yet determinable but management does not expect the decision to have a material impact on Emera's adjusted net income. BLPC will seek to clarify aspects of the FTC decision in its compliance filing and is also considering filing a submission to the FTC for a review of the decision. BLPC expects a decision on final rates from the FTC in 2023.

On January 14, 2022, the GBPA issued its decision on GBPC's rate application. The decision, which became effective April 1, 2022, allows for an increase in revenues of $3.5 million USD. The new rates include a regulatory ROE of 12.84 per cent.

Effective November 1, 2022, GBPC's fuel pass through charge was increased due to an increase in global oil prices impacting the unhedged fuel cost. In 2023, the fuel pass through charge will be adjusted monthly, in-line with actual fuel costs.

18

In 2023, capital investment in the Other Electric Utilities segment is expected to be approximately $65 million USD (2022 - $48 million USD), primarily in more efficient and cleaner sources of generation, including renewables and battery storage.

## Other

The Other segment includes those business operations that in a normal year are below the required threshold for reporting as separate segments; and corporate expense and revenue items that are not directly allocated to the operations of Emera's subsidiaries and investments.

Business operations in the Other segment include Emera Energy and Emera Technologies LLC ('ETL'). Emera Energy consists of EES, a wholly owned physical energy marketing and trading business and an equity investment in a 50 per cent joint venture ownership of Bear Swamp, a 660 MW pumped storage hydroelectric facility in northwestern Massachusetts. ETL is a wholly owned technology company focused on finding ways to deliver renewable and resilient energy to customers.

Corporate items included in the Other segment are certain corporate-wide functions including executive management, strategic planning, treasury services, legal, financial reporting, tax planning, corporate business development, corporate governance, investor relations, risk management, insurance, acquisition and disposition related costs, gains or losses on select assets sales, and corporate human resource activities. It includes interest revenue on intercompany financings and interest expense on corporate debt in both Canada and the United States. It also includes costs associated with corporate activities that are not directly allocated to the operations of Emera's subsidiaries and investments.

Earnings from EES are generally dependent on market conditions. In particular, volatility in natural gas and electricity markets, which can be influenced by weather, local supply constraints and other supply and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1 and Q4 usually providing the greatest opportunity for earnings. EES is generally expected to deliver annual adjusted net income within its guidance range of $15 to $30 million USD ($45 to $70 million USD of margin).

Absent the TGH award in Q4 2022, the adjusted net loss from the Other segment is expected to be higher in 2023, based on EES returning to its normal earnings range in 2023 and increased interest expense. The increase is expected to be partially offset by decreased taxes due to a higher net loss.

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

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# CONSOLIDATED BALANCE SHEET HIGHLIGHTS

Significant changes in the Consolidated Balance Sheets between December 31, 2021 and December 31, 2022 include:

| millions of dollars | Increase (Decrease) | Explanation |
| --- | --- | --- |
| Assets |  |  |
| Cash and cash equivalents | $(84) | Decreased due to increased investment in PP&E at regulated utilities and dividends on common stock. These were partially offset by proceeds from short-term debt issuance at Emera and Tampa Electric, increased proceeds under committed credit facilities at NSPI and Emera, cash from operations, and issuance of common stock |
| Inventory | 231 | Increased due to higher commodity prices at Emera Energy and NSPI, increased materials inventory at Tampa Electric and the effect of the FX translation of Emera's foreign affiliates |
| Derivative instruments (current and long-term) | 95 | Increased due to reversal of 2021 contracts at Emera Energy |
| Regulatory assets (current and long-term) | 1,054 | Increased due to higher fuel cost recovery clauses at Tampa Electric, increased FAM deferrals, driven mainly by increased Cap-and Trade emissions compliance charges, and increased deferred income tax regulatory assets at NSPI, the effect of the FX translation of Emera's foreign affiliates, recognition of storm reserve asset at Tampa Electric due to restoration costs from Hurricane Ian in excess of the storm reserve liability, and increased pension and post-retirement plan deferrals at Tampa and NSPI. These were partially offset by recovery of gas costs from the NMGC 2021 winter event |
| Receivables and other assets (current and long-term) | 1,165 | Increased due to higher gas transportation assets and higher trade receivables due to higher commodity prices at Emera Energy, fuel option receivable at NMGC and the effect of the FX translation of Emera's foreign affiliates |
| PP&E, net of accumulated depreciation and amortization | 2,643 | Increased due to the effect of the FX translation of Emera's foreign affiliates, and capital additions. These were partially offset by reclassification of Seacoast's pipeline lateral on commencement of the lease in 2022 |
| Net investment in direct finance and sales type leases | 101 | Increased due to commencement of the pipeline lease at Seacoast in 2022 |
| Goodwill | 316 | Increased due to the effect of the FX translation of Emera's foreign affiliates, partially offset by the GBPC impairment |

20

| millions of dollars | Increase (Decrease) | Explanation |
| --- | --- | --- |
| Liabilities and Equity |  |  |
| Short-term debt and long-term debt (including current portion) | $2,644 | Increased due to the effect of the FX translation of Emera's foreign affiliates, issuance of short-term debt at Emera and Tampa Electric, and net borrowings under the committed credit facility at NSPI and Emera |
| Accounts payable | 540 | Increased due to increased commodity prices at Emera Energy, Tampa Electric and NMGC, the effect of the FX translation of Emera's foreign affiliates, higher cash collateral position on derivative instruments at NSPI, and timing of payments at Tampa Electric and NSPI |
| Deferred income tax liabilities, net of deferred income tax assets | 386 | Increased due to tax deductions in excess of accounting depreciation related to PP&E, increase in net regulatory assets, decrease in net derivative liabilities, and the effect of the FX translation of Emera's foreign affiliates, partially offset by net increase in tax loss carryforwards |
| Derivative instruments (current and long-term) | 396 | Increased due to new contracts in 2022, partially offset by reversal of 2021 contracts and changes in existing positions at Emera Energy |
| Regulatory liabilities (current and long-term) | 218 | Increased due to NMGC gas hedge settlements and the effect of the FX translation of Emera's foreign affiliates, partially offset by decreased storm reserve at Tampa Electric due to restoration costs incurred from Hurricane Ian |
| Pension and post-retirement liabilities | (89) | Decreased due to favourable changes in actuarial assumptions, partially offset by lower investment returns |
| Other liabilities (current and long-term) | 170 | Increased due to accrued emissions compliance charges at NSPI and the effect of the FX translation of Emera's foreign affiliates |
| Common stock | 520 | Increased due to Emera's ATM equity program and shares issued under the DRIP |
| Accumulated other comprehensive income | 553 | Increased due to the effect of the FX translation of Emera's foreign affiliates |
| Retained earnings | 236 | Increased due to net income in excess of dividends paid. |

## OTHER DEVELOPMENTS

### USGAAP Reporting Extension

Emera was granted exemptive relief by Canadian securities regulators on September 13, 2022, and under the Companies Act (Nova Scotia) on October 12, 2022, each allowing Emera to continue to report its financial results in accordance with USGAAP (collectively the 'Exemptive Relief'). The Exemptive Relief will terminate on the earliest of: (i) January 1, 2027; (ii) if the Company ceases to have rate-regulated activities, the first day of the Company's financial year that commences after the Company ceases to have rate-regulated activities; and (iii) the first day of the Company's financial year that commences on or following the later of: (a) the effective date prescribed by the International Accounting Standards Board ('IASB') for the mandatory application of a standard within IFRS specific to entities with rate-regulated activities ('Mandatory Rate-regulated Standard'); and (b) two years after the IASB publishes the final version of a Mandatory Rate-regulated Standard. The Exemptive Relief replaces similar relief that had been granted to Emera in 2018 and would have expired by no later than January 1, 2024.

### Increase in Common Dividends

On September 22, 2022, the Emera Board of Directors approved an increase in the annual common share dividend rate to $2.76 from $2.65. The first payment was effective November 15, 2022. Emera also extended its dividend growth rate target of four to five per cent through 2025.

21

## Appointments

Effective July 1, 2022, Michael Barrett was appointed Executive Vice President and General Counsel for Emera. Mr. Barrett was most recently the General Counsel for Emera.

Effective June 30, 2022, Bruce Marchand was appointed Chief Risk and Sustainability Officer for Emera. Mr. Marchand was most recently the Chief Legal and Compliance Officer for Emera.

## FINANCIAL HIGHLIGHTS

### Florida Electric Utility

All amounts are reported in USD, unless otherwise stated.

| For the millions of USD (except as indicated) | Three months ended December 31 |  | Year ended December 31 |  |
| --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 |
| Operating revenues - regulated electric | $597 | $561 | $2,523 | $2,174 |
| Regulated fuel for generation and purchased power | $201 | $212 | $832 | $713 |
| Contribution to consolidated net income | $91 | $67 | $458 | $369 |
| Contribution to consolidated net income - CAD | $124 | $85 | $596 | $462 |
| Average fuel costs in dollars per MWh | $41 | $44 | $39 | $34 |

The impact of the change in the FX rate increased CAD earnings for the three months and year ended December 31, 2022, by $10 million and $23 million, respectively.

### Net Income

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

| For the millions of USD | Three months ended December 31 | Year ended December 31 |
| --- | --- | --- |
| Contribution to consolidated net income - 2021 | $67 | $369 |
| Increased operating revenues due to higher rates effective January 2022, higher fuel recovery clause revenue as a result of increased fuel costs, and customer growth. Year-over-year also increased due to favourable weather | 36 | 349 |
| Fuel for generation and purchased power decreased in Q4 due to lower natural gas prices quarter-over-quarter. Year-over-year, fuel increased due to higher natural gas prices | 11 | (119) |
| Increased OM&G due to timing of deferred clause recoveries. Year-over-year the increase is also due to higher transmission and distribution costs, higher benefit costs and higher insurance costs | (6) | (52) |
| Increased depreciation and amortization due to additions to facilities and the in-service of generation projects | (5) | (15) |
| Increased interest expense due to higher interest rates and higher borrowings to support Tampa Electric's ongoing operations, including fuel under-recoveries, and capital investments | (16) | (32) |
| Decreased AFUDC earnings due to timing of Big Bend modernization and solar projects | (4) | (10) |
| Increased income tax expense year-over-year primarily due to increased income before provision for income taxes | - | (36) |
| Other | 8 | 4 |
| Contribution to consolidated net income - 2022 | $91 | $458 |

22

## Operating Revenues - Regulated Electric

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

|  | Electric Revenues (millions of USD) |  | Electric Sales Volumes (Gigawatt hours ('GWh')) |  |
| --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 |
| Residential | $1,381 | $1,156 | 10,109 | 9,941 |
| Commercial | 666 | 602 | 6,300 | 6,144 |
| Industrial | 176 | 172 | 2,111 | 2,122 |
| Other (1) | 300 | 244 | 2,352 | 2,000 |
| Total | $2,523 | $2,174 | 20,872 | 20,207 |

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

## Regulated Fuel for Generation and Purchased Power

Annual production volumes are summarized in the following table:

|  | Production Volumes (GWh) |  |
| --- | --- | --- |
|  | 2022 | 2021 |
| Natural gas | 17,083 | 16,142 |
| Purchased power | 1,685 | 2,301 |
| Solar | 1,492 | 1,252 |
| Coal | 1,325 | 1,342 |
| Total | 21,585 | 21,037 |

Tampa Electric's fuel costs are affected by commodity prices and generation mix that is largely dependent on economic dispatch of the generating fleet, bringing the lowest cost options on first (renewable energy from solar), such that the incremental cost of production increases as sales volumes increase. Generation mix may also be affected by plant outages, plant performance, availability of lower priced short-term purchased power, availability of renewable solar generation, and compliance with environmental standards and regulations.

## Regulatory Environment

Tampa Electric is regulated by the FPSC and is also subject to regulation by the FERC. The FPSC sets rates at a level that allows utilities such as Tampa Electric to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC rate setting hearings which can occur at the initiative of Tampa Electric, the FPSC or other interested parties. For further details on Tampa Electric's regulatory environment, base rates and recovery mechanisms, refer to note 7 in the consolidated financial statements.

## Canadian Electric Utilities

| For the millions of dollars (except as indicated) | Three months ended December 31 |  | Year ended December 31 |  |
| --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 |
| Operating revenues - regulated electric | $421 | $389 | $1,675 | $1,501 |
| Regulated fuel for generation and purchased power (1) | $173 | $263 | $950 | $817 |
| Contribution to consolidated adjusted net income | $46 | $67 | $222 | $241 |
| NSPML unrecoverable costs | $ - | $ - | $(7) | $ - |
| Contribution to consolidated net income | $46 | $67 | $215 | $241 |
| Average fuel costs in dollars per MWh | $61 | $93 | $85 | $75 |

(1) Regulated fuel for generation and purchased power includes NSPL's FAM and fixed cost deferrals on the Consolidated Statements of Income, however it is excluded in the segment overview.

23

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

| For the millions of dollars | Three months ended December 31 |  | Year ended December 31 |  |
| --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 |
| NSPI | $23 | $43 | $131 | $141 |
| Equity investment in LIL | 15 | 14 | 55 | 51 |
| Equity investment in NSPML (1) | 8 | 10 | 36 | 49 |
| Contribution to consolidated adjusted net income | $46 | $67 | $222 | $241 |

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

## Net Income

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

| For the millions of dollars | Three months ended December 31 | Year ended December 31 |
| --- | --- | --- |
| Contribution to consolidated net income - 2021 | $67 | $241 |
| Increased operating revenues due to increased electric revenues related to recovery of fuel costs from an industrial customer, increased residential and commercial class sales volumes, and increased electricity pricing effective January 1, 2022. Quarter-over-quarter increase partially offset by unfavourable weather | 32 | 174 |
| Decreased regulated fuel for generation and purchased power quarter-over-quarter due to lower Cap-and-Trade Program provision and lower Maritime Link assessment costs. Increased regulated fuel for generation and purchased power year-over year due to increased Nova Scotia Cap-and-Trade program provision, increased commodity prices and higher sales volume, partially offset by a favourable change in generation mix | 90 | (133) |
| Decreased FAM and fixed cost deferrals year-over-year due to increased recovery of fuel costs, partially offset by increased Cap-and-Trade provision. Quarter-over-quarter decreased due to increased recovery of fuel costs and decreased Cap-and-Trade provision | (120) | (16) |
| Increased OM&G due to higher costs for storm restoration, IT, power generation, and regulatory affairs | (20) | (47) |
| Increased depreciation and amortization due to increased PP&E in-service | (5) | (13) |
| Decreased income tax expense primarily due to increased tax deductions in excess of accounting depreciation and amortization related to PP&E and deferrals and decreased income before provision for income taxes. This was partially offset by the benefit of tax loss carryforwards recognized as a deferred income tax regulatory liability | 7 | 18 |
| Year-over-year decrease in net income from equity investment in NSPML primarily due to the Maritime Link holdback | (2) | (13) |
| NSPML unrecoverable costs | - | (7) |
| Other | (3) | 11 |
| Contribution to consolidated net income - 2022 | $46 | $215 |

24

## NSPI

### Operating Revenues - Regulated Electric

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

|  | Electric Revenues (millions of dollars) |  | Electric Sales Volumes (GWh) |  |
| --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 |
| Residential | $834 | $797 | 4,822 | 4,661 |
| Commercial | 427 | 407 | 3,006 | 2,902 |
| Industrial | 353 | 237 | 2,480 | 2,480 |
| Other | 28 | 27 | 148 | 153 |
| Total | $1,642 | $1,468 | 10,456 | 10,196 |

### Regulated Fuel for Generation and Purchased Power

Annual production volumes are summarized in the following table:

|  | Production Volumes (GWh) |  |
| --- | --- | --- |
|  | 2022 | 2021 |
| Coal | 3,771 | 4,623 |
| Natural gas | 1,650 | 1,673 |
| Purchased power - other | 910 | 865 |
| Petcoke | 897 | 519 |
| Oil | 251 | 81 |
| Total non-renewables | 7,479 | 7,761 |
| Purchased power | 2,423 | 1,977 |
| Wind and hydro | 1,105 | 1,007 |
| Biomass | 127 | 160 |
| Total renewables | 3,655 | 3,144 |
| Total production volumes | 11,134 | 10,905 |

NSPI's fuel costs are affected by commodity prices and generation mix, which is largely dependent on economic dispatch of the generating fleet. NSPI brings the lowest cost options on stream first after renewable energy from IPPs, including Community Feed-in Tariff ('COMFIT') participants, for which NSPI has power purchase agreements in place, and the NS Block of energy, including the Supplemental Energy Block. NSPI pays annual assessments approved by the UARB to NSPML for use of the Maritime Link, and therefore utilizes all transmitted NS Block and Supplemental Energy Block energy received which carries no additional fuel cost.

NSPI-owned hydro and wind have no fuel cost component. After hydro and wind, historically, petcoke and coal have the lowest per-unit fuel cost, followed by natural gas. Oil, biomass and purchased power have the next lowest fuel cost, depending on the relative pricing of each. Generation mix may also be affected by plant outages, availability of renewable generation, availability of energy from the NS Block, plant performance, and compliance with environmental standards including the Cap-and-Trade Program.

The generation mix has undergone significant transformation with the addition of non-dispatchable renewable energy sources such as wind, including from IPPs and COMFIT, which typically have a higher cost per MWh than NSPI-owned generation or other purchased power sources.

The provision for the Cap-and-Trade program was an $18 million recovery for the three months ended December 31, 2022 (2021 - $35 million expense) and a $134 million expense for the year ended December 31, 2022 (2021 - $38 million expense). For further information on this non-cash accrual, the estimated costs and the FAM regulatory balance, refer to note 7 in the consolidated financial statements.

25

## Regulatory Environment - NSPI

NSPI is a public utility as defined in the Public Utilities Act and is subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI's operations and expenditures. Electricity rates for NSPI's customers are subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings held from time to time at NSPI's or the UARB's request. For further details on NSPI's regulatory environment and recovery mechanisms, refer to note 7 in the consolidated financial statements.

## Gas Utilities and Infrastructure

All amounts are reported in USD, unless otherwise stated.

| For the millions of USD (except as indicated) | Three months ended December 31 |  | Year ended December 31 |  |
| --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 |
| Operating revenues - regulated gas (1) | $372 | $307 | $1,296 | $1,006 |
| Operating revenues - non-regulated | 2 | 2 | 12 | 12 |
| Total operating revenue | $374 | $309 | $1,308 | $1,018 |
| Regulated cost of natural gas | $181 | $139 | $614 | $375 |
| Contribution to consolidated net income | $53 | $44 | $170 | $157 |
| Contribution to consolidated net income - CAD | $72 | $55 | $221 | $198 |

(1) Operating revenues - regulated gas includes $13 million of finance income from Brunswick Pipeline (2021 - $12 million) for the three months ended December 31, 2022 and $47 million (2021 - $46 million) for the year ended December 31 2022; however, it is excluded from the gas revenues and cost of natural gas analysis below.

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

| For the millions of USD | Three months ended December 31 |  | Year ended December 31 |  |
| --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 |
| PGS | $17 | $17 | $82 | $77 |
| NMGC | 22 | 15 | 35 | 33 |
| Other | 14 | 12 | 53 | 47 |
| Contribution to consolidated net income | $53 | $44 | $170 | $157 |

The impact of the change in the FX rate increased CAD earnings for the three months and year ended December 31, 2022, by $4 million and $6 million, respectively.

26

## Net Income

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

| For the millions of USD | Three months ended December 31 | Year ended December 31 |
| --- | --- | --- |
| Contribution to consolidated net income - 2021 | $44 | $157 |
| Increased gas revenues due to higher purchased gas adjustment clause revenues at NMGC and PGS as a result of higher gas prices, higher off-system sales, and customer growth at PGS | 55 | 280 |
| Increased asset optimization revenues at NMGC. In 2022, NMGC's 30 per cent share of asset optimization revenues were well above the historical average, and may not reoccur in 2023 | 10 | 10 |
| Increased cost of natural gas sold due to higher gas prices at NMGC and PGS, and higher off-system sales at PGS | (42) | (239) |
| Increased OM&G primarily due to higher labour and benefits costs at NMGC and PGS, and higher contractor costs at PGS | (3) | (22) |
| Increased depreciation and amortization due to asset growth at PGS and NMGC. Year-over-year, the increase was more than offset by the reversal of accumulated depreciation as a result of the rate case settlement at PGS | (2) | 6 |
| Increased interest expense due to higher interest rates | (4) | (10) |
| Increased income tax expense primarily due to increased income before provision for income taxes | (2) | (7) |
| Other | (3) | (5) |
| Contribution to consolidated net income - 2022 | $53 | $170 |

## Operating Revenues - Regulated Gas

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

|  | Gas Revenues (millions of USD) |  | Gas Volumes (Therms) |  |
| --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 |
| Residential | $614 | $510 | 421 | 405 |
| Commercial | 354 | 301 | 836 | 799 |
| Industrial (1) | 64 | 53 | 1,429 | 1,434 |
| Other (2) | 217 | 96 | 227 | 137 |
| Total (3) | $1,249 | $960 | 2,913 | 2,775 |

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

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

(3) Total gas revenue excludes $47 million of finance income from Brunswick Pipeline (2021 - $46 million).

## Regulated Cost of Natural Gas

PGS and NMGC purchase gas from various suppliers depending on the needs of their customers. In Florida, gas is delivered to the PGS distribution system through interstate pipelines on which PGS has firm transportation capacity for delivery by PGS to its customers. NMGC's natural gas is transported on major interstate pipelines and NMGC's intrastate transmission and distribution system for delivery to customers.

In Florida, natural gas service is unbundled for non-residential customers and residential customers who use more than 1,999 therms annually and elect the option. In New Mexico, NMGC is required, if requested, to provide transportation-only services for all customer classes. The commodity portion of bundled sales is included in operating revenues, at the cost of the gas on a pass-through basis, therefore no net earnings effect when a customer shifts to transportation-only sales.

27

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

|  | Gas Volumes by Type (millions of Therms) |  |
| --- | --- | --- |
|  | 2022 | 2021 |
| Transportation | 2,206 | 2,154 |
| System supply | 707 | 621 |
| Total | 2,913 | 2,775 |

## Regulatory Environments

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

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

For further information on PGS and NMGC's regulatory environment and recovery mechanisms, refer to note 7 in the consolidated financial statements.

## Other Electric Utilities

All amounts are reported in USD, unless otherwise stated.

| For the millions of USD (except as indicated) | Three months ended December 31 |  | Year ended December 31 |  |
| --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 |
| Operating revenues - regulated electric | $98 | $98 | $398 | $355 |
| Regulated fuel for generation and purchased power | $54 | $52 | $223 | $175 |
| Contribution to consolidated adjusted net income | $7 | $4 | $23 | $16 |
| Contribution to consolidated adjusted net income - CAD | $8 | $5 | $29 | $20 |
| GBPC Impairment charge | $54 | $ - | $54 | $ - |
| Equity securities MTM gain (loss) | $1 | $2 | $(4) | $1 |
| Contribution to consolidated net income | $(46) | $6 | $(35) | $17 |
| Contribution to consolidated net income - CAD | $(62) | $7 | $(48) | $21 |
| Electric sales volumes (GWh) | 301 | 330 | 1,239 | 1,262 |
| Electric production volumes (GWh) | 336 | 357 | 1,340 | 1,359 |
| Average fuel cost in dollars per MWh | $161 | $146 | $166 | $129 |

The impact of the change in the FX rate increased net loss by $3 million for the three months and year ended December 31, 2022 and had a minimal impact on adjusted net income for the same periods.

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

| For the millions of USD | Three months ended December 31 |  | Year ended December 31 |  |
| --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 |
| BLPC | $5 | $6 | $11 | $11 |
| GBPC | 1 | - | 10 | 8 |
| Other | 1 | (2) | 2 | (3) |
| Contribution to consolidated adjusted net income | $7 | $4 | $23 | $16 |

28

## Net Income

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

| For the millions of USD | Three months ended December 31 | Year ended December 31 |
| --- | --- | --- |
| Contribution to consolidated net income - 2021 | $6 | $17 |
| Increased operating revenues - regulated electric year-over-year due to higher fuel revenue at BLPC as a result of higher fuel prices, partially offset by the sale of Domlec in Q1 2022 | - | 43 |
| Increased fuel for generation and purchased power as a result of higher fuel prices at BLPC | (2) | (48) |
| Decreased OM&G due to the sale of Domlec in Q1 2022 and lower generation costs at GBPC, partially offset by the recognition of Hurricane Dorian insurance proceeds at GBPC in 2021 | 11 | 17 |
| Goodwill impairment charge at GBPC | (54) | (54) |
| Decreased MTM gain on equity securities held in BLPC | (1) | (5) |
| Other | (6) | (5) |
| Contribution to consolidated net income - 2022 | $(46) | $(35) |

## Regulatory Environments

BLPC is regulated by the FTC, an independent regulator. Rates are set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on capital invested.

GBPC is regulated by the GBPA. Rates are set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on rate base.

For further details on BLPC and GBPC's regulatory environments and recovery mechanisms, refer to note 7 in the consolidated financial statements.

## Other

| For the millions of dollars | Three months ended December 31 |  | Year ended December 31 |  |
| --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 |
| Marketing and trading margin (1) (2) | $72 | $39 | $143 | $102 |
| Other non-regulated operating revenue | 3 | 5 | 16 | 30 |
| Total operating revenues - non-regulated | $75 | $44 | $159 | $132 |
| Contribution to consolidated adjusted net income (loss) | $(1) | $(44) | $(218) | $(198) |
| MTM gain (loss), after-tax (3) | 304 | 154 | 179 | (214) |
| Contribution to consolidated net income (loss) | $303 | $110 | $(39) | $(412) |

(1) Marketing and trading margin represents EES's purchases and sales of natural gas and electricity, pipeline and storage capacity costs and energy asset management services' revenues.

(2) Marketing and trading margin excludes a MTM gain, pre-tax of $430 million in Q4 2022 (2021 - $212 million gain) and a gain of $281 million for the year ended December 31, 2022 (2021 - $289 million loss).

(3) Net of income tax expense of $124 million for the three months ended December 31, 2022 (2021 - $63 million expense) and $73 million expense for the year ended December 31, 2022 (2021 - $86 million recovery).

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

| For the millions of dollars | Three months ended December 31 |  | Year ended December 31 |  |
| --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 |
| Emera Energy | $41 | $17 | $70 | $54 |
| Corporate - see breakdown of adjusted contribution below | (37) | (57) | (267) | (231) |
| Emera Technologies | (5) | (4) | (18) | (17) |
| Other | - | - | (3) | (4) |
| Contribution to consolidated adjusted net income (loss) | $(1) | $(44) | $(218) | $(198) |

29

## MTM Adjustments

Emera Energy's 'Marketing and trading margin', 'Non-regulated fuel for generation and purchased power', 'Income from equity investments' and 'Income tax expense (recovery)' are affected by MTM adjustments. Management believes excluding the effect of MTM valuations, and changes thereto, from income until settlement better matches the financial effect of these contracts with the underlying cash flows. Variance explanations of the MTM changes for this quarter and for the year are explained in the chart below.

Emera Energy has a number of asset management agreements ('AMA') with counterparties, including local gas distribution utilities, power utilities and natural gas producers in North America. The AMAs involve Emera Energy buying or selling gas for a specific term, and the corresponding release of the counterparties' gas transportation/storage capacity to Emera Energy. MTM adjustments on these AMAs arise on the price differential between the point where gas is sourced and where it is delivered. At inception, the MTM adjustment is offset fully by the value of the corresponding gas transportation asset, which is amortized over the term of the AMA contract.

Subsequent changes in gas price differentials, to the extent they are not offset by the accounting amortization of the gas transportation asset, will result in MTM gains or losses recorded in income. MTM adjustments may be substantial during the term of the contract, especially in the winter months of a contract when delivered volumes and market pricing are usually at peak levels. As a contract is realized, and volumes reduce, MTM volatility is expected to decrease. Ultimately, the gas transportation asset and the MTM adjustment reduce to zero at the end of the contract term. As the business grows, and AMA volumes increase, MTM volatility resulting in gains and losses may also increase.

Emera Corporate has FX forwards to manage the cash flow risk of forecasted USD cash inflows. Fluctuations in the FX rate result in MTM gains or losses recorded in income.

## Net Income

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

| For the millions of dollars | Three months ended December 31 | Year ended December 31 |
| --- | --- | --- |
| Contribution to consolidated net income (loss) - 2021 | $110 | $(412) |
| Increased marketing and trading margin due to weather driven market conditions that increased pricing and volatility, which created profitable opportunities for Emera Energy. Year-over-year increase also reflected sustained higher pricing and volatility | 33 | 41 |
| Increased OM&G, pre-tax, primarily due to the timing of long-term compensation and related hedges | (19) | (55) |
| Increased interest expense, pre-tax, due to increased interest rates and increased total debt | (17) | (27) |
| Increased FX loss, pre-tax, primarily due to realized gains in 2021 on FX hedges entered into to hedge USD denominated operating unit earnings exposure | (9) | (28) |
| Increased income tax recovery primarily due to increased losses before provision for income taxes | 5 | 25 |
| Increased preferred stock dividends due to issuance of preferred shares in 2021 | (2) | (13) |
| TGH award, after tax and legal costs | 45 | 45 |
| Increased MTM gain, after-tax, due to change in existing positions and larger reversal of MTM losses in 2022, partially offset by higher amortization of gas transportation assets in 2022 at Emera Energy | 150 | 393 |
| Other | 7 | (8) |
| Contribution to consolidated net income (loss) - 2022 | $303 | $(39) |

30

## Emera Energy

EES derives revenue and earnings from the wholesale marketing and trading of natural gas and electricity within the Company's risk tolerances, including those related to value-at-risk ('VaR') and credit exposure. EES purchases and sells physical natural gas and electricity, the related transportation and transmission capacity rights, and provides energy asset management services. The primary market area for the natural gas and power marketing and trading business is northeastern North America, including the Marcellus and Utica shale supply areas. EES also participates in the Florida, United States Gulf Coast and Midwest/Central Canadian natural gas markets. Its counterparties include electric and gas utilities, natural gas producers, electricity generators and other marketing and trading entities. EES operates in a competitive environment, and the business relies on knowledge of the region's energy markets, understanding of pipeline and transmission infrastructure, a network of counterparty relationships and a focus on customer service. EES manages its commodity risk by limiting open positions, utilizing financial products to hedge purchases and sales, and investing in transportation capacity rights to enable movement across its portfolio.

## Corporate

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

| For the millions of dollars | Three months ended December 31 |  | Year ended December 31 |  |
| --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 |
| Operating expenses (1) | $20 | $1 | $83 | $28 |
| Interest expense | 83 | 65 | 291 | 264 |
| Income tax recovery | (35) | (18) | (109) | (75) |
| Preferred dividends | 16 | 14 | 63 | 50 |
| TGH award, after tax and legal costs | (45) | - | (45) | - |
| Other (2)(3) | (2) | (5) | (16) | (36) |
| Corporate adjusted net loss (4) | $(37) | $(57) | $(267) | $(231) |

(1) Operating expenses include OM&G and depreciation. In Q4 2021, OM&G and depreciation were offset by a decrease in long-term incentive compensation. The value of long-term incentive compensation and related hedges are impacted by changes in Emera's period end share price.

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

(3) Includes a realized, pre-tax net loss of $5 million (2021 - $5 million gain) quarter-to-date and a $6 million loss for the year ended December 31, 2022 (2021 - $18 million gain) on FX hedges, as discussed above.

(4) Excludes a MTM gain, after-tax of $9 million for the three months ended December 31, 2022 (2021 - $3 million loss) and a MTM loss, after-tax of $12 million for the year ended December 31, 2023 (2021 - $14 million loss)

## LIQUIDITY AND CAPITAL RESOURCES

The Company generates internally sourced cash from its various regulated and non-regulated energy investments. Utility customer bases are diversified by both sales volumes and revenues among customer classes. Emera's non-regulated businesses provide diverse revenue streams and counterparties to the business. Circumstances that could affect the Company's ability to generate cash include changes to global macro-economic conditions, downturns in markets served by Emera, impact of fuel commodity price changes on collateral requirements and timely recoveries of fuel costs from customers, the loss of one or more large customers, regulatory decisions affecting customer rates and the recovery of regulatory assets, and changes in environmental legislation. Emera's subsidiaries are generally in a financial position to contribute cash dividends to Emera provided they do not breach their debt covenants, where applicable, after giving effect to the dividend payment, and maintain their credit metrics.

31

Emera's future liquidity and capital needs will be predominately for working capital requirements, ongoing rate base investment, business acquisitions, greenfield development, dividends and debt servicing. Emera has an $8 - 9 billion capital investment plan over the 2023-to-2025 period (including a $240 million equity investment in the LIL in 2023), mainly focused in Florida. This plan includes significant rate base investments across the portfolio in renewable and cleaner generation, infrastructure modernization and customer-focused technologies. Capital investments at the regulated utilities are subject to regulatory approval.

Emera plans to use cash from operations and debt raised at the utilities to support normal operations, repayment of existing debt, and capital requirements. Debt raised at certain of the Company's utilities is subject to applicable regulatory approvals. Equity requirements in support of the Company's capital investment plan are expected to be funded through the issuance of preferred equity and the issuance of common equity through Emera's DRIP and ATM program.

Emera has credit facilities with varying maturities that cumulatively provide $4.7 billion of credit, with approximately $1.1 billion undrawn and available at December 31, 2022. The Company was holding a cash balance of $332 million at December 31, 2022. For further discussion, refer to the 'Debt Management' section below. For additional information regarding the credit facilities, refer to notes 23 and 25 in the consolidated financial statements.

## Consolidated Cash Flow Highlights

Significant changes in the Consolidated Statements of Cash Flows between the years ended December 31, 2022 and 2021 include:

| millions of dollars | 2022 | 2021 | $ Change |
| --- | --- | --- | --- |
| Cash, cash equivalents and restricted cash, beginning of period | $417 | $254 | $163 |
| Provided by (used in): |  |  |  |
| Operating cash flow before changes in working capital | 1,147 | 1,337 | (190) |
| Change in working capital | (234) | (152) | (82) |
| Operating activities | $913 | $1,185 | $(272) |
| Investing activities | (2,569) | (2,332) | (237) |
| Financing activities | 1,555 | 1,311 | 244 |
| Effect of exchange rate changes on cash, cash equivalents and restricted cash | 16 | (1) | 17 |
| Cash, cash equivalents, and restricted cash, end of period | $332 | $417 | $(85) |

### Cash Flow from Operating Activities

Net cash provided by operating activities decreased $272 million to $913 million for the year ended December 31, 2022, compared to $1,185 million in 2021.

Cash from operations before changes in working capital decreased $190 million for the year ended December 31, 2022. This decrease was due to under-recovery of clause-related costs primarily due to higher natural gas prices at Tampa Electric, unfavourable changes in Tampa Electric's storm reserve balance as a result of Hurricane Ian, increased fuel for generation and purchased power at NSPI, and decreased long-term payables due to the Nova Scotia Cap-and-Trade accrued emissions compliance charges being reclassified to other current liabilities as the liability is anticipated to be settled in 2023. This was partially offset by the 2021 deferral of gas costs at NMGC resulting from the extreme cold weather event, increased revenues at Tampa Electric and NSPI, favourable changes in regulatory liabilities due to the NMGC gas hedge settlement, TGH award, and increased marketing and trading margin at Emera Energy.

32

Changes in working capital decreased operating cash flows by $82 million for the year ended December 31, 2022. This decrease was due to unfavourable changes in accounts receivable at NMGC due to the gas hedge settlement, unfavourable changes in accounts receivable at NSPI, unfavourable changes in cash collateral positions on derivative instruments at NSPI, and the required prepayment of income taxes and related interest at NSPI. This was partially offset by the Nova Scotia Cap-and-Trade accrued emissions compliance charges, favourable changes in cash collateral positions at Emera Energy, and favourable changes in accounts payable at Tampa Electric and NMGC.

#### **Cash Flow used in Investing Activities**

Net cash used in investing activities increased $237 million to $2,569 million for the year ended December 31, 2022, compared to $2,332 million in 2021. The increase was due to higher capital investment in 2022.

Capital expenditures for the year ended December 31, 2022, including AFUDC, were $2,646 million compared to $2,420 million in 2021. Details of 2022 capital spending by segment are shown below:

- $1,481 million - Florida Electric Utility (2021 - $1,408 million);
- $518 million - Canadian Electric Utilities (2021 - $374 million);
- $578 million - Gas Utilities and Infrastructure (2021 - $522 million);
- $63 million - Other Electric Utilities (2021 - $111 million); and
- $6 million - Other (2021 - $5 million).

#### **Cash Flow from Financing Activities**

Net cash provided by financing activities increased $244 million to $1,555 million for the year ended December 31, 2022, compared to $1,311 million in 2021. This increase was due to higher proceeds of short-term debt at Tampa Electric, proceeds from committed credit facilities at NSPI, and term loan issuance at Emera in 2022. These were partially offset by the issuance of preferred shares in 2021, lower proceeds of long-term debt at Tampa Electric, and net proceeds of long-term debt at NMGC in 2021.

#### **Working Capital**

As at December 31, 2022, Emera's cash and cash equivalents were $310 million (2021 - $394 million) and Emera's investment in non-cash working capital was $1,173 million (2021 - $491 million). Of the cash and cash equivalents held at December 31, 2022, $250 million was held by Emera's foreign subsidiaries (2021 - $194 million). A portion of these funds are invested in countries that have certain exchange controls, approvals, and processes for repatriation. Such funds are available to fund local operating and capital requirements unless repatriated.

33

## Contractual Obligations

As at December 31, 2022, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:

| millions of dollars | 2023 | 2024 | 2025 | 2026 | 2027 | Thereafter | Total |
| --- | --- | --- | --- | --- | --- | --- | --- |
| Long-term debt principal | $574 | $1,613 | $262 | $3,110 | $946 | $9,937 | $16,442 |
| Interest payment obligations (1) | 720 | 699 | 653 | 566 | 472 | 6,995 | 10,105 |
| Transportation (2) | 693 | 516 | 423 | 383 | 367 | 2,817 | 5,199 |
| Purchased power (3) | 269 | 243 | 237 | 228 | 243 | 2,145 | 3,365 |
| Fuel, gas supply and storage | 1,161 | 282 | 138 | 40 | 5 | 1 | 1,627 |
| Capital projects | 264 | 89 | 4 | 1 | - | - | 358 |
| Asset retirement obligations | 15 | 2 | 2 | 1 | 1 | 415 | 436 |
| Pension and post-retirement obligations (4) | 38 | 31 | 31 | 82 | 59 | 178 | 419 |
| Equity investment commitments (5) | 240 | - | - | - | - | - | 240 |
| Other | 154 | 142 | 132 | 49 | 42 | 189 | 708 |
|  | $4,128 | $3,617 | $1,882 | $4,460 | $2,135 | $22,677 | $38,899 |

(1) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at December 31, 2022, including any expected required payment under associated swap agreements.

(2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $144 million related to a gas transportation contract between PGS and SeaCoast through 2040.

(3) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths.

(4) The estimated contractual obligation is calculated as the current legislatively required contributions to the registered funded pension plans (excluding the possibility of wind-up), plus the estimated costs of further benefit accruals contracted under NSPI's Collective Bargaining Agreement and estimated benefit payments related to other unfunded benefit plans.

(5) Emera has a commitment to make a final equity contribution to the LIL upon its commissioning. Once commissioned, the commercial agreements between Emera and Nalcor require true ups to finalize the respective investment obligations of the parties in relation to the Maritime Link and LIL.

NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. In February 2022, the UARB issued its decision and Board Order approving NSPML's requested rate base of approximately $1.8 billion. In December 2022, the UARB approved the collection of $164 million from NSPI for the recovery of Maritime Link costs in 2023. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to UARB approval.

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

## Forecasted Gross Consolidated Capital Expenditures

The 2023 forecasted gross consolidated capital expenditures are as follows:

| millions of dollars | Florida Electric Utility | Canadian Electric Utilities | Gas Utilities and Infrastructure | Other Electric Utilities | Other | Total |
| --- | --- | --- | --- | --- | --- | --- |
| Generation | $276 | $120 | $ - | $36 | $ - | $432 |
| New renewable generation | 402 | - | - | 4 | - | 406 |
| Transmission | 100 | 74 | - | - | - | 174 |
| Distribution | 479 | 121 | - | 34 | - | 634 |
| Gas transmission and distribution | - | - | 639 | - | - | 639 |
| Facilities, equipment, vehicles, and other | 516 | 60 | - | 17 | 11 | 604 |
|  | $1,773 | $375 | $639 | $91 | $11 | $2,889 |

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## Debt Management

In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to committed syndicated revolving and non-revolving bank lines of credit in either CAD or USD per the table below.

| millions of dollars | Maturity | Credit Facilities | Utilized | Undrawn and Available |
| --- | --- | --- | --- | --- |
| Emera - Unsecured committed revolving credit facility | June 2027 | $900 | $403 | $497 |
| TEC (in USD) - Unsecured committed revolving credit facility (1) | December 2026 | 800 | 620 | 180 |
| NSPI - Unsecured committed revolving credit facility | December 2027 | 800 | 497 | 303 |
| Emera - Unsecured non-revolving facility | December 2023 | 400 | 400 | - |
| Emera - Unsecured non-revolving facility | August 2023 | 400 | 400 | - |
| TEC (in USD) - Unsecured non-revolving facility (2) | December 2023 | 400 | 400 | - |
| TECO Finance (in USD) - Unsecured committed revolving credit facility | December 2026 | 400 | 355 | 45 |
| NSPI - Unsecured non-revolving facility | July 2024 | 400 | 400 | - |
| NMGC (in USD) - Unsecured revolving credit facility | December 2026 | 125 | 45 | 80 |
| NMGC (in USD) - Unsecured non-revolving facility | March 2024 | 80 | 80 | - |
| Other (in USD) - Unsecured committed revolving credit facilities | Various | 21 | 7 | 14 |

(1) This facility is available for use by Tampa Electric and PGS. At December 31, 2022, $554 million USD was used by Tampa Electric and $66 million USD was used by PGS.

(2) This facility is available for use by Tampa Electric and PGS. At December 31, 2022, $300 million USD was used by Tampa Electric and $100 million USD was used by PGS.

Emera and its subsidiaries have certain financial and other covenants associated with their debt and credit facilities. Covenants are tested regularly, and the Company is in compliance with covenant requirements as at December 31, 2022. Emera's significant covenant is listed below:

|  | Financial Covenant | Requirement | As at December 31, 2022 |
| --- | --- | --- | --- |
| Emera |  |  |  |
| Syndicated credit facilities | Debt to capital ratio | Less than or equal to 0.70 to 1 | 0.57 : 1 |

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

### Florida Electric Utilities

On December 13, 2022, TEC amended its 364-day non-revolving credit facility to extend the maturity date from December 16, 2022 to December 13, 2023 and reduced the facility amount from $500 million USD to $400 million USD. There were no other significant changes in commercial terms from the prior agreement.

On September 15, 2022, TEC repaid a $250 million USD note upon maturity. The note was repaid using existing credit facilities.

On July 12, 2022, TEC completed an issuance of $600 million USD senior notes. The issuance included $300 million USD senior notes that bear an interest rate of 3.875 per cent with a maturity date of July 12, 2024, and $300 million USD senior notes that bear an interest rate of 5 per cent with a maturity date of July 15, 2052. Proceeds from the issuance were used to repay TEC's $470 million USD commercial paper, due in 2022, and for general corporate purposes.

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### Canadian Electric Utilities

On December 16, 2022, NSPI amended its revolving operating credit facility to extend the maturity date from December 16, 2026 to December 16, 2027 and increase the amount of the facility from $600 million to $800 million. There were no other significant changes in commercial terms from the prior agreement.

On July 15, 2022, NSPI entered into a $400 million non-revolving term credit facility which matures on July 15, 2024. The credit facility contains customary representation and warranties, events of default and financial and other covenants, and bears interest at Bankers' Acceptances or prime rate advances, plus a margin. Proceeds from this facility were used for general corporate purposes.

### Gas Utilities and Infrastructure

On September 23, 2022, NMGC amended its $80 million USD, unsecured, non-revolving term credit facility to extend the maturity from September 23, 2022, to March 22, 2024. There were no other changes in commercial terms from the prior agreement.

On June 30, 2022, Brunswick Pipeline amended its non-revolving credit agreement to extend the maturity from June 30, 2025 to June 30, 2026. There were no other changes in commercial terms from the prior agreement.

### Other Electric Utilities

On March 25, 2022, ECI amended its amortizing floating rate notes to extend the maturity from March 25, 2022 to March 25, 2027. There were no other changes in commercial terms from the prior agreement.

### Other

On December 16, 2022, Emera amended its $900 million revolving operating credit facility to extend the maturity date from June 30, 2026 to June 30, 2027. There were no other significant changes in commercial terms from the prior agreement.

On December 16, 2022, Emera amended its $400 million non-revolving term credit facility to extend the maturity from December 16, 2022 to December 16, 2023. There were no other significant changes in commercial terms from the prior agreement.

On August 2, 2022, Emera entered into a $400 million non-revolving term facility which matures on August 2, 2023. The credit agreement contains customary representation and warranties, events of default and financial and other covenants and bears interest at Bankers' Acceptances or prime rate advances, plus a margin. Proceeds from this facility were used for general corporate purposes.

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## Credit Ratings

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

|  | Fitch (1) | S&P (2)(3) | Moody's (4)(5) | DBRS (6) |
| --- | --- | --- | --- | --- |
| Emera Inc. | BBB (Negative) | BBB- (Negative) | Baa3 (Negative) | N/A |
| TECO Energy/TECO Finance | N/A | N/A | N/A | N/A |
| TEC | A (Negative) | BBB+ (Negative) | A3 (Negative) | N/A |
| NMGC | BBB+ (Negative) | N/A | N/A | N/A |
| NSPI | N/A | BBB- (Negative) | N/A | BBB (high)(stable) |

(1) On November 21, 2022, Fitch Ratings ('Fitch') affirmed its BBB issuer rating for Emera Inc. Fitch also affirmed the A- issuer and A unsecured debt ratings for TEC and BBB+ for NMGC. Emera and subsidiaries' outlook was changed to negative from stable.

(2) On November 21, 2022, S&P Global Ratings ('S&P') affirmed its BBB issuer rating for Emera Inc. and TECO Energy, while affirming the BBB+ issuer credit ratings for TEC. S&P downgraded NSPI's issue-level and senior unsecured debt ratings to BBB-. Emera and subsidiaries' outlook remained at negative.

(3) On October 24, 2022, S&P affirmed its BBB issuer rating for Emera Inc. S&P also affirmed ratings on NSPI, TECO Energy, and TEC affirming the BBB+ issuer credit ratings for NSPI and TEC. Emera and subsidiaries' outlook was changed to negative from stable.

(4) On November 2, 2022, Moody's Investor Services ('Moody's') affirmed its Baa3 issuer rating for Emera Inc. Moody's also affirmed ratings on TECO Finance and TEC, affirming the TECO Finance Baa1 issuer rating and A3 issuer rating for TEC. Emera and subsidiaries' outlook was changed to negative from stable.

(5) On June 2, 2022, Moody's affirmed its Baa1 issuer rating for TECO Finance. Moody's also affirmed TEC's A3 issuer rating and changed the outlook to stable from positive.

(6) On December 20, 2022, DBRS ('Dominion Bond Rating Service') downgraded its issuer credit and senior unsecured rating for NSPI to BBB (high). NSPI's outlook remained unchanged at stable.

The downgrades from both S&P and DBRS of NSPI were attributed to their view of the enactment of Bill 212, 'Public Utilities Act (amended)', as a political intervention in the regulatory process that resulted in an increase in political risk and a reduction in the stability and predictability of NSPI's regulatory environment.

## Guaranteed Debt

As of December 31, 2022, the Company had $2.75 billion USD senior unsecured notes ('U.S. Notes') outstanding.

The U.S. Notes are fully and unconditionally guaranteed, on a joint and several basis, by Emera and Emera US Holdings Inc. (in such capacity, the 'Guarantor Subsidiaries'). Emera owns, directly or indirectly, all of the limited and general partnership interests in Emera US Finance LP. Other subsidiaries of the Company do not guarantee the U.S. Notes (such subsidiaries are referred to as the 'Non-Guarantor Subsidiaries') however, Emera has unrestricted access to the assets of consolidated entities.

In compliance with Rule 13-01 of Regulation S-X, the Company is including summarized financial information for Emera, Emera US Holdings Inc., and Emera US Finance LP (together, the 'Obligor Group'), on a combined basis after transactions and balances between the combined entities have been eliminated. Investments in and equity earnings of the Non-Guarantor Subsidiaries have been excluded from the summarized financial information.

The Obligor Group was not determined using geographic, service line or other similar criteria and, as a result the summarized financial information includes portions of Emera's domestic and international operations. Accordingly, this basis of presentation is not intended to present Emera's financial condition or results of operations for any purpose other than to comply with the specific requirements for guarantor reporting.

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## Summarized Statement of Income (loss)

The Company recognized income related to guaranteed debt under the following categories:

| For the millions of dollars | Year ended December 31 |  |
| --- | --- | --- |
|  | 2022 | 2021 |
| Loss from operations | $(73) | $(21) |
| Net losses (1) | $(131) | $(86) |

(1) Includes $262 million in interest and dividend income, net, from non-guarantor subsidiaries.

## Summarized Balance Sheet

The Company has the following categories on the balance sheet related to guaranteed debt:

| As at millions of dollars | December 31 |  |
| --- | --- | --- |
|  | 2022 | 2021 |
| Current assets (1) | $172 | $329 |
| Goodwill | 6,012 | 5,628 |
| Other assets (2) | 6,402 | 6,027 |
| Total assets (3) | $12,586 | $11,984 |
| Current liabilities (4) | $1,903 | $888 |
| Long-term liabilities (5) | 6,431 | 6,403 |
| Total liabilities | $8,334 | $7,291 |

(1) Includes $144 million (2021 - $140 million) in amounts due from non-guarantor subsidiaries.

(2) Includes $6,058 million (2021 - $5,749 million) in amounts due from non-guarantor subsidiaries.

(3) Excludes investments in non-guarantor subsidiaries. Consolidated Emera total assets are $39,742 million (2021 - $34,244 million).

(4) Includes $392 million (2021 - $346 million) due to non-guarantor subsidiaries.

(5) Includes $769 million (2021 - $776 million) due to non-guarantor subsidiaries.

## Outstanding Stock Data

### Common Stock

| Issued and outstanding: | millions of shares | millions of dollars |
| --- | --- | --- |
| Balance, December 31, 2021 | 261.07 | $7,242 |
| Issuance of common stock under ATM program (1) | 4.07 | 248 |
| Issued under the DRIP, net of discounts | 4.21 | 238 |
| Senior management stock options exercised and Employee Share Purchase Plan | 0.60 | 34 |
| Balance, December 31, 2022 | 269.95 | $7,762 |

(1) In Q4 2022, 278,545 common shares were issued under Emera's ATM program at an average price of $54.06 per share for gross proceeds of $15 million ($15 million net of after-tax issuance costs). For the year ended December 31, 2022, 4,072,469 common shares were issued under Emera's ATM program at an average price of $61.31 per share for gross proceeds of $250 million ($248 million net of after-tax issuance costs). As at December 31, 2022, an aggregate gross sales limit of $207 million remained available for issuance under the ATM program.

As at February 16, 2023, the amount of issued and outstanding common shares was 271.4 million.

If all outstanding stock options were converted as at February 16, 2023, an additional 2.9 million common shares would be issued and outstanding.

### Preferred Stock

As at February 16, 2023, Emera had the following preferred shares issued and outstanding: Series A - 4.9 million; Series B - 1.1 million; Series C - 10.0 million; Series E - 5.0 million; Series F - 8.0 million; Series H - 12.0 million; Series J - 8.0 million, and Series L - 9.0 million. Emera's preferred shares do not have voting rights unless the Company fails to pay, in aggregate, eight quarterly dividends.

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# PENSION FUNDING

For funding purposes, Emera determines required contributions to its largest defined benefit pension plans based on smoothed asset values. This reduces volatility in the cash funding requirement as the impact of investment gains and losses are recognized over a three-year period. The cash required in 2023 for defined benefit pension plans is expected to be $44 million (2022 - $45 million). All pension plan contributions are tax deductible and will be funded with cash from operations.

Emera's defined benefit pension plans employ a long-term strategic approach with respect to asset allocation, real return and risk. The underlying objective is to earn an appropriate return, given the Company's goal of preserving capital with an acceptable level of risk for the pension fund investments.

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 $44 million for 2023 (2022 - $41 million).

## Defined Benefit Pension Plan Summary

in millions of dollars

| Plans by region | TECO Energy | NSPI | Caribbean | Total |
| --- | --- | --- | --- | --- |
| Assets as at December 31, 2022 | $880 | $1,273 | $10 | $2,163 |
| Accounting obligation at December 31, 2022 | $902 | $1,240 | $16 | $2,158 |
| Accounting expense during fiscal 2022 | $10 | $(3) | $1 | $8 |

## Off-Balance Sheet Arrangements

### Defeasance

Upon privatization in 1992, NSPI became responsible for managing a portfolio of defeasance securities that provide principal and interest streams to match the related defeased debt, which at December 31, 2022 totalled $200 million (2021 - $200 million). The securities are held in trust for an affiliate of the Province of Nova Scotia. Approximately 66 per cent of the defeasance portfolio consists of investments in the related debt, eliminating all risk associated with this portion of the portfolio; the remaining defeasance portfolio has a market value higher than the related debt, reducing the future risk of this portion of the portfolio.

### Guarantees and Letters of Credit

Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December 31, 2022:

TECO Energy has issued a guarantee in connection with SeaCoast's performance of obligations under a gas transportation precedent agreement. The guarantee is for a maximum potential amount of $45 million USD if SeaCoast fails to pay or perform under the contract. The guarantee expires five years after the gas transportation precedent agreement termination date, which was terminated on January 1, 2022. In the event that TECO Energy's and Emera's long-term senior unsecured credit ratings are downgraded below investment grade by Moody's or S&P, TECO Energy would be required to provide its counterparty a letter of credit or cash deposit of $27 million USD.

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TECO Energy issued a guarantee in connection with SeaCoast's performance obligations under a firm service agreement, which expires on December 31, 2055, subject to two extension terms at the option of the counterparty with a final expiration date of December 31, 2071. The guarantee is for a maximum potential amount of $13 million USD if SeaCoast fails to pay or perform under the firm service agreement. In the event that TECO Energy's long-term senior unsecured credit ratings are downgraded below investment grade by Moody's or S&P, TECO Energy would need to provide either a substitute guarantee from an affiliate with an investment grade credit rating or a letter of credit or cash deposit of $13 million USD.

Emera Inc. has issued a guarantee of up to $35 million USD relating to outstanding notes of GBPC. The guarantee for the notes will expire in May 2023.

Emera Inc. has issued a guarantee of $66 million USD relating to outstanding notes of ECI. This guarantee will automatically terminate on the date upon which the obligations have been repaid in full.

NSPI has issued guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated ('NSPEMI'), in the amount of $119 million USD (2021 - $118 million USD) with terms of varying lengths.

The Company has standby letters of credit and surety bonds in the amount of $145 million USD (December 31, 2021 - $148 million USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed annually as required.

Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The expiry date of this letter of credit was extended to June 2023. The amount committed as at December 31, 2022 was $63 million (December 31, 2021 - $64 million).

## DIVIDEND PAYOUT RATIO

Emera has provided annual dividend growth guidance of four to five per cent through 2025. The Company targets a long-term dividend payout ratio of adjusted net income of 70 to 75 per cent, and while the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to return to that range over time. Emera's common share dividends paid in 2022 were $2.6775 ($0.6625 in Q1, Q2, and Q3 and $0.6900 in Q4) per common share and $2.5750 ($0.6375 in Q1, Q2, and Q3 and $0.6625 in Q4) per common share for 2021, representing a dividend payout ratio of 75 per cent in 2022 (2021 - 129 per cent) and a dividend payout ratio of adjusted net income of 83 per cent in 2022 (2021 - 91 per cent).

On September 22, 2022, the Emera Board of Directors approved an increase in the annual common share dividend rate to $2.76 from $2.65. The first quarterly dividend payment at the increased rate was paid on November 15, 2022.

## TRANSACTIONS WITH RELATED PARTIES

In the ordinary course of business, Emera provides energy and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Intercompany balances and intercompany transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. All material amounts are under normal interest and credit terms.

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Significant transactions between Emera and its associated companies are as follows:

- Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Consolidated Statements of Income. NSPI's expense is reported in Regulated fuel for generation and purchased power, totalling $157 million for the year ended December 31, 2022 (2021 - $149 million). NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments. For further details, refer to the "Business Overview and Outlook - Canadian Electric Utilities - ENL" and "Contractual Obligations" sections.
- Natural gas transportation capacity purchases from M&NP are reported in the Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $9 million for the year ended December 31, 2022 (2021 - $19 million).

There were no significant receivables or payables between Emera and its associated companies reported on Emera's Consolidated Balance Sheets as at December 31, 2022 and at December 31, 2021.

## ENTERPRISE RISK AND RISK MANAGEMENT

Emera has an enterprise-wide risk management process, overseen by its Enterprise Risk Management Committee ("ERMC") and monitored by the Board of Directors, to ensure an effective, consistent and coherent approach to risk management. Certain risk management activities for Emera are overseen by the ERMC to ensure such risks are appropriately identified, assessed, monitored and subject to appropriate controls.

The Board of Directors established a Risk and Sustainability Committee ("RSC") in September 2021. The mandate of the RSC is to assist the Board in carrying out its risk and sustainability oversight responsibilities. The RSC's mandate includes oversight of the Company's Enterprise Risk Management framework, including the identification, assessment, monitoring and management of enterprise risks. It also includes oversight of the Company's approach to sustainability and its performance relative to its sustainability objectives.

The Company's financial risk management activities are focused on those areas that most significantly impact profitability, quality and consistency of income, and cash flow. Emera's risk management focus extends to key operational risks including safety and environment, which represent core values of Emera. In this section, Emera describes the principal risks that management believes could materially affect its business, revenues, operating income, net income, net assets, liquidity or capital resources. The nature of risk is such that no list is comprehensive, and other risks may arise or risks not currently considered material may become material in the future.

### Regulatory and Political Risk

The Company's rate-regulated subsidiaries and certain investments subject to significant influence are subject to risk of the recovery of costs and investments. Regulatory and political risk can include changes in regulatory frameworks, shifts in government policy, legislative changes, and regulatory decisions.

As cost-of-service utilities with an obligation to serve customers, Emera's utilities operate under formal regulatory frameworks, and must obtain regulatory approval to change or add rates and/or riders. Emera also holds investments in entities in which it has significant influence, and which are subject to regulatory and political risk including NSPML, LIL, and M&NP. As a regulated Group II pipeline, the tolls of Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to the regulatory approval process described above. In the absence of a complaint, the CER does not normally undertake a detailed examination of Brunswick Pipeline's tolls, which are subject to a firm service agreement, expiring in 2034, with Repsol Energy North America Canada Partnership. The agreement provides for a predetermined toll increase in the fifth and fifteenth year of the contract.

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Regulators administer legislation covering material aspects of the utilities' businesses, including customer rates and/or riders, the underlying allowed ROEs, deemed capital structures, capital investment, the terms and conditions for the provision of service, performance standards, and affiliate transactions. Costs and investments can be recovered upon approval by the respective regulator as an adjustment to rates and/or riders, which normally require a public hearing process or may be mandated by other governmental bodies. During public hearing processes, consultants and customer representatives scrutinize the costs, actions and plans of these rate-regulated companies, and their respective regulators determine whether to allow recovery and to adjust rates based upon the evidence and any contrary evidence from other parties. In some circumstances, other government bodies may influence the setting of rates. Regulatory decisions, legislative changes, and prolonged delays in the recovery of costs or regulatory assets could result in decreased rate affordability for customers and could materially affect Emera and its utilities.

Emera's utilities generally manage this risk through transparent regulatory disclosure, ongoing stakeholder and government consultation, and multi-party engagement on aspects such as utility operations, regulatory audits, rate filings and capital plans. The subsidiaries employ a collaborative regulatory approach through technical conferences and, where appropriate, negotiated settlements.

Changes in government and shifts in government policy and legislation can impact the commercial and regulatory frameworks under which Emera and its subsidiaries operate. This includes initiatives regarding deregulation or restructuring of the energy industry. Deregulation or restructuring of the energy industry may result in increased competition and unrecovered costs that could adversely affect operations, net income and cash flows. State and local policies in some United States jurisdictions have sought to prevent or limit the ability of utilities to provide customers the choice to use natural gas while in other jurisdictions policies have been adopted to prevent limitations on the use of natural gas. Changes in applicable state or local laws and regulations, including electrification legislation, could adversely impact PGS and NMGC.

Emera cannot predict future legislative, policy, or regulatory changes, whether caused by economic, political or other factors, or its ability to respond in an effective and timely manner or the resulting compliance costs. Government interference in the regulatory process can undermine regulatory stability, predictability, and independence, and could have a material adverse effect on the Company.

### **Global Climate Change Risk**

The Company is subject to risks that may arise from the impacts of climate change. There is increasing public concern about climate change and growing support for reducing carbon dioxide emissions. Municipal, state, provincial and federal governments have been setting policies and enacting laws and regulations to deal with climate change impacts in a variety of ways, including decarbonization initiatives and promotion of cleaner energy and renewable energy generation of electricity. Refer to 'Changes in Environmental Legislation' risk below. Insurance companies have begun to limit their exposure to coal-fired electricity generation and are evaluating the medium and long-term impacts of climate change which may result in fewer insurers, more restrictive coverage and increased premiums. Refer to the 'Markets' section below and 'Uninsured Risk'.

Climate change may lead to increased frequency and intensity of weather events and related impacts such as storms, ice storms, hurricanes, cyclones, heavy rainfall, extreme winds, wildfires, flooding and storm surge. The potential impacts of climate change, such as rising sea levels and larger storm surges from more intense hurricanes, can combine to produce even greater damage to coastal generation and other facilities. Climate change is also characterized by rising global temperatures. Increased air temperatures may bring increased frequency and severity of wildfires within the Company's service territories. Refer to 'Weather Risk' and 'System Operating and Maintenance Risks'.

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The Company has made significant investments to facilitate the use of renewable and lower-carbon energy including wind generation, the Maritime Link in Atlantic Canada, and in Florida, solar generation and modernization of the Big Bend Power Station. Tampa Electric has taken significant steps to reduce overall emissions at its facilities as a result of its capital investment plan which has and will continue to reduce carbon dioxide emissions. In 2022, NSPI achieved reductions of carbon dioxide emissions of approximately 45 per cent from 2005 levels. NSPI expects to exceed the Canadian target of 40-45 per cent reduction by 2030, as set out in the Canadian Net-Zero Emissions Accountability Act. Both the Government of Nova Scotia and the Government of Canada have enacted or introduced legislation that includes goals of net-zero GHG emissions by 2050. The Province of Nova Scotia has established targets with respect to the percentage of renewable energy in NSPI's generation mix, reductions in GHG emissions, as well as the goal to phase out coal-fired electricity generation by 2030. Failure to meet such goals by 2030 could result in material fines, penalties, other sanctions and adverse reputational impacts. NSPI continues to work with both the provincial and federal governments on measures to seek to address their carbon reduction goals. Future compliance with provincial and federal GHG emission caps, coal phase out requirements and targets, and renewable standards has been challenged as a result of the constraints imposed by the enactment of Bill 212, 'Public Utilities Act (amended)'. Within Emera's natural gas utilities, there are ongoing efforts to reduce methane and carbon dioxide emissions through replacement of aging infrastructure, more efficient operations, operational and supply chain optimization, and support of public policy initiatives that address the effects of climate change.

The Company's long-term capital investment plan includes significant investment across the portfolio in renewable and cleaner generation, infrastructure modernization, storm hardening, energy storage and customer-focused technologies. All these initiatives contribute toward mitigating the potential impacts of climate change. The Company continues to engage with government, regulators, industry partners and stakeholders to share information and participate in the development of climate change related policies and initiatives.

#### *Physical Impacts*

The Company is subject to physical risks that arise, or may arise, from global climate change, including damage to operating assets from more frequent and intense weather events and from wildfires due to warming air temperatures and increasing drought conditions. Substantially all of the Company's fossil fueled generation assets are located at or near coastal sites and, as such, are exposed to the separate and combined effects of rising sea levels and increasing storm intensity, including storm surges and flooding. Refer to 'Weather Risk' for further information.

These risks are mitigated to an extent through features such as flood walls at certain plants and through the location of plants on higher ground. Planned investments in under-grounding parts of the electricity infrastructure contribute to risk mitigation, as does insurance coverage (for assets other than electricity transmission and distribution assets). In addition, implementation of regulatory mechanisms for recovery of costs, such as storm reserves and regulatory deferral accounts, help smooth out the recovery of storm restoration costs over time.

#### *Reputation*

Failure to address issues related to climate change could affect Emera's reputation with stakeholders, its ability to operate and grow, and the Company's access to, and cost of, capital. Refer to 'Liquidity and Capital Market Risk'. The Company seeks to mitigate this in part by moving away from higher-carbon generation in favour of lower-carbon generation and non-emitting renewable generation.

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### *Markets*

Changing carbon-related costs, policy and regulatory changes and shifts in supply and demand factors could lead to more expensive or more scarce products and services that are required by the Company in its operations. This could lead to supply shortages, delivery delays and the need to source alternate products and services. The Company seeks to mitigate these risks through close monitoring of such developments and adaptive changes to supply chain procurement strategies.

Given concerns regarding carbon-emitting generation, those assets and businesses may, over time, become difficult (or uneconomic) to insure in commercial insurance markets. In the short term, this may be mitigated through increased investment in engineered protection or alternative risk financing (such as funded self-insurance or regulatory structures, including storm reserves). Longer-term mitigation may be achieved through infrastructure siting decisions and further engineered protections. This risk may also be mitigated through the continued transition away from high-carbon generation sources to sources with low or zero carbon dioxide emissions.

### *Policy*

Government and regulatory initiatives, including greenhouse gas emissions standards, air emissions standards and generation mix standards, are being proposed and adopted in many jurisdictions in response to concerns regarding the effects of climate change. In some jurisdictions, government policy has included timelines for mandated shutdowns of coal generating facilities, percentage of electricity generation from renewables, carbon pricing, emissions limits and cap and trade mechanisms. Over the medium and longer terms, this could potentially lead to a significant portion of hydrocarbon infrastructure assets being subject to additional regulation and limitations in respect of GHG emissions and operations. The Company is subject to climate-related and environmental legislative and regulatory requirements. Such legislative and regulatory initiatives could adversely affect Emera's operations and financial performance. Refer to 'Regulatory and Political Risk' and 'Changes in Environmental Legislation' risk. The Company seeks to mitigate these risks through active engagement with governments and regulators to pursue transition strategies that meet the needs of customers, stakeholders and the Company. This has included NSPI's participation in negotiated equivalency agreements in Nova Scotia to provide for an affordable transition to lower-carbon generation. Equivalency agreements allow NSPI to achieve compliance with federal GHG emissions regulations by meeting provincial legislative and regulatory requirements as they are deemed to be equivalent. There is no guarantee that such equivalency agreements will be renewed or remain in force in the future.

### *Regulatory*

Depending on the regulatory response to government legislation and regulations, the Company may be exposed to the risk of reduced recovery through rates in respect of the affected assets. Valuation impairments could result from such regulatory outcomes. Mitigation efforts in respect of these risks include active engagement with policy makers and regulators to find mechanisms to avoid such impacts while being responsive to customers' and stakeholders' objectives.

### *Legal*

The Company could face litigation or regulatory action related to environmental harms from carbon dioxide emissions or climate change public disclosure issues. The Company addresses these risks through compliance with all relevant laws, emissions reduction strategies, and public disclosure of climate change risks.

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## *Water Resources*

For thermal plants requiring cooling water, reduced availability of water resulting from climate change could adversely impact operations or the costs of operations. The Company seeks ways to reduce and recycle water as it does in its Polk power plant in Florida, where recovered and treated wastewater is used in operations to reduce reliance on fresh water supplies in an area where water is not as abundant as in other markets.

The Company operates hydroelectric generation in certain of its markets. Such generation depends on availability of water and the hydrological profile of water sources. Changes in precipitation patterns, water temperatures and air temperatures could adversely affect the availability of water and consequently the amount of electricity that may be produced from such facilities. The Company is reinvesting in the efficiency of certain hydroelectric generation facilities to increase generation capacity and continues to monitor changing hydrology patterns. Such issues may also affect the availability of third-party owned hydroelectricity purchased power sources.

## **Weather Risk**

The Company is subject to risks that arise or may arise from weather including seasonal variations impacting energy sales, more frequent and intense weather events, changing air temperatures, wildfires and extreme weather conditions associated with climate change. Refer to 'Global Climate Change Risk'.

Fluctuations in the amount of electricity or natural gas used by customers can vary significantly in response to seasonal changes in weather and could impact the operations, results of operations, financial condition, and cash flows of the Company's utilities. For example, Tampa Electric could see lower demand in summer months if temperatures are cooler than expected. Further, extreme weather conditions such as hurricanes and other severe weather conditions which may be associated with climate change could cause these seasonal fluctuations to be more pronounced. In the absence of a regulatory recovery mechanism for unanticipated costs, such events could influence the Company's results of operations, financial conditions or cash flows.

Extreme weather events create a risk of physical damage to the Company's assets. High winds can impact structures and cause widespread damage to transmission and distribution infrastructure, solar generation, and wind powered generation. Increased frequency and severity of weather events increases the likelihood that the duration of power outages and fuel supply disruptions could increase. Increased frequency and intensity of flooding and storm surge could adversely affect the operations of utilities and in particular generation assets. The impact of extreme weather events would be amplified if the same events affect multiple utilities.

Each of Emera's regulated electric utilities have programs for storm hardening of transmission and distribution facilities to minimize damage, but there can be no assurance that these measures will fully mitigate the risk. This risk to transmission and distribution facilities is typically not insured, and as such the restoration cost is generally recovered through regulatory processes, either in advance through reserves or designated self-insurance funds, or after the fact through the establishment of regulatory assets. Recovery is not assured and is subject to prudence 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.

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## Changes in Environmental Legislation

Emera is subject to regulation by federal, provincial, state, regional and local authorities regarding environmental matters, primarily related to its utility operations. This includes laws setting GHG emissions standards and air emissions standards. Emera is also subject to laws regarding waste management, wastewater discharges and aquatic and terrestrial habitats.

Changes to GHG emissions standards and air emissions standards could adversely affect Emera's operations and financial performance. Legislative or regulatory changes could influence decisions regarding early retirement of generation facilities and may result in stranded costs if the Company is not able to fully recover the costs and investment in the affected generation assets. Recovery is not assured and is subject to prudence review. Legislative or regulatory changes may curtail sales of natural gas to new customers, which could reduce future customer growth in Emera's natural gas businesses. Stricter environmental laws and enforcement of such laws in the future could increase Emera's exposure to additional liabilities and costs. These changes could also affect earnings and strategy by changing the nature and timing of capital investments.

In addition to imposing continuing compliance obligations, there are permit requirements, laws and regulations authorizing the imposition of penalties for non-compliance, including fines, injunctive relief, and other sanctions. The cost of complying with current and future environmental requirements is, and may be, material to Emera. Failure to comply with environmental requirements or to recover environmental costs in a timely manner through rates, could have a material adverse effect on Emera. In addition, Emera's business could be materially affected by changes in government policy, utility regulation, and environmental and other legislation that could occur in response to environmental and climate change concerns.

Emera manages its environmental risk by operating in a manner that is respectful and protective of the environment and in compliance with applicable legal requirements and Company policy. Emera has implemented this policy through the development and application of environmental management systems in its operating subsidiaries. Comprehensive audit programs are in place to regularly test compliance.

## Cybersecurity Risk

Emera is exposed to potential risks related to cyberattacks and unauthorized access. The Company increasingly relies on IT systems network, and cloud infrastructure to manage its business and safely operate its assets, including controls for interconnected systems of generation, distribution and transmission as well as financial, billing and other business systems. Emera also relies on third-party service providers to conduct business. As the Company operates critical infrastructure, it may be at greater risk of cyberattacks by third parties, which could include nation-state-controlled parties. This risk may be further elevated by geo-political risks such as the ongoing conflict between Russia and Ukraine.

Cyberattacks can reach the Company's assets and information via their interfaces with third parties or the public internet and gain access to critical infrastructures. Cyberattacks can also occur via personnel with direct access to critical assets or trusted networks. Methods used to attack critical assets could include general purpose or energy-sector-specific malware delivered via network transfer, removable media, viruses, attachments, or links in e-mails. The methods used by attackers are continuously evolving and can be difficult to predict and detect.

Despite security measures in place, that are described below, the Company's systems, assets and information could experience security breaches that could cause system failures, disrupt operations, or adversely affect safety. Such breaches could compromise customer, employee-related or other information systems and could result in loss of service to customers, unavailability of critical assets, safety issues, or the release, destruction, or misuse of critical, sensitive or confidential information. These breaches could also delay delivery or result in contamination or degradation of hydrocarbon products the Company transports, stores or distributes.

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Cyberattacks or unauthorized accesses may cause costs, losses and damages all, or some of which, may not be recoverable (through insurance, legal, regulatory cost recovery or other processes). This could materially adversely affect Emera's business and financial results including its reputation with customers, regulators, governments and financial markets. Resulting costs could include, amongst others, response, recovery and remediation costs, increased protection or insurance costs and costs arising from damages and losses incurred by third parties. If any such security breaches occur, there is no assurance they can be adequately addressed in a timely manner.

The Company seeks to manage these risks by aligning to a common set of cybersecurity standards and policies derived, in part, on the National Institute of Standards and Technology's Cyber Security Framework, periodic security testing, program maturity objectives, cybersecurity incident readiness program, and employee communication and training. With respect to certain of its assets, the Company is required to comply with rules and standards relating to cybersecurity and IT including, but not limited to, those mandated by bodies such as the North American Electric Reliability Corporation, Northeast Power Coordinating Council, and the United States Department of Homeland Security. The status of key elements of the Company's cybersecurity program is reported to the RSC.

### **Public Health Risk**

An outbreak of infectious disease, a pandemic or a similar public health threat, such as the COVID-19 pandemic, or a fear of any of the foregoing, could adversely impact the Company, including causing operating, supply chain and project development delays and disruptions, labour shortages and shutdowns (including as a result of government regulation and prevention measures), which could have a negative impact on the Company's operations.

Any adverse changes in general economic and market conditions arising as a result of a public health threat could negatively impact demand for electricity and natural gas, revenue, operating costs, timing and extent of capital expenditures, results of financing efforts, or credit risk and counterparty risk; which could result in a material adverse effect on the Company's business. The Company maintains pandemic and business contingency plans in each of its operations to manage and help mitigate the impact of any such public health threat.

### **Energy Consumption Risk**

Emera's rate-regulated utilities are affected by demand for energy based on changing customer patterns due to fluctuations in a number of factors including general economic conditions, weather events, customers' focus on energy efficiency, changes in rates, and advancements in new technologies such as rooftop solar, electric vehicles and battery storage. Government policies promoting distributed generation, and new technology developments that enable those policies, have the potential to impact how electricity enters the system and how it is bought and sold. In addition, increases in distributed generation may impact demand resulting in lower load and revenues. These changes could negatively impact Emera's operations, rate base, net earnings, and cash flows. The Company's rate-regulated utilities are focused on understanding customer demand, energy efficiency, and government policy to ensure that the impact of these activities benefit customers, that they do not negatively impact the reliability of the energy service and that they are addressed through regulations.

### **Foreign Exchange Risk**

The Company is exposed to foreign currency exchange rate changes. Emera operates internationally, with an increasing amount of the Company's net income earned outside of Canada. As such, Emera is exposed to movements in exchange rates between the CAD and, particularly, the USD, which could positively or adversely affect results.

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Consistent with the Company's risk management policies, Emera manages currency risks through matching United States denominated debt to finance its United States operations and may use foreign currency derivative instruments to hedge specific transactions and earnings exposure. The Company may enter FX forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases, revenue streams and capital expenditures, and on net income earned outside of Canada. The regulatory framework for the Company's rate-regulated subsidiaries permits the recovery of prudently incurred costs, including FX.

The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries do not impact net income as they are reported in Accumulated Other Comprehensive Income (Loss) ('AOCI') ('AOCL').

### **Liquidity and Capital Market Risk**

Liquidity risk relates to Emera's ability to ensure sufficient funds are available to meet its financial obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity and capital needs could be financed through internally generated cash flows, asset sales, short-term credit facilities, and ongoing access to capital markets. The Company reasonably expects liquidity sources to exceed capital needs.

Emera's access to capital and cost of borrowing is subject to several risk factors, including financial market conditions, market disruptions and ratings assigned by credit rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or cause the Company to issue securities with less than preferred terms and conditions. Emera's growth plan requires significant capital investments in PP&E and the risk associated with changes in interest rates could have an adverse effect on the cost of financing. The Company's future access to capital and cost of borrowing may be impacted by various market disruptions. The inability to access cost-effective capital could have a material impact on Emera's ability to fund its growth plan.

Emera is subject to financial risk associated with changes in its credit ratings. There are a number of factors that rating agencies evaluate to determine credit ratings, including the Company's business, its regulatory framework and legislative environment, political interference in the regulatory process, the ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to climate change-related impacts, including increased frequency and severity of hurricanes and other severe weather events. A decrease in a credit rating could result in higher interest rates in future financings, increased borrowing costs under certain existing credit facilities, limit access to the commercial paper market, or limit the availability of adequate credit support for subsidiary operations. For certain derivative instruments, if the credit ratings of the Company were reduced below investment grade, the full value of the net liability of these positions could be required to be posted as collateral. Emera manages these risks by actively monitoring and managing key financial metrics with the objective of sustaining investment grade credit ratings.

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

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## General Economic Risk

The Company has exposure to the macro-economic conditions in North America and in other geographic regions in which Emera operates. Like most utilities, economic factors such as consumer income, employment and housing affect demand for electricity and natural gas and, in turn, the Company's financial results. Adverse changes in general economic conditions and inflation may impact the ability of customers to afford rate increases arising from increases to fuel, operating, capital, environmental compliance, and other costs, and therefore could materially affect Emera and its utilities. This may also result in higher credit and counterparty risk, adverse shifts in government policy and legislation, and/or increased risk to full and timely recovery of costs and regulatory assets.

### *Interest Rate Risk*

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

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

As with most other utilities and other similar yield-returning investments, Emera's share price may be affected by changes in interest rates and could underperform the market in an environment of rising interest rates.

### *Inflation Risk*

The Company may be exposed to changes in inflation that may result in increased operating and maintenance costs, capital investment, and fuel costs compared to the revenues provided by customer rates. Emera's utilities have budgeting and forecasting processes to identify inflationary risk factors and measure operating performance, as well as collective bargaining agreements that mitigate the short-term impact of inflation on labour costs.

## Project Development and Land Use Rights Risk

The Company's capital plan includes significant investment in generation, infrastructure modernization, and customer-focused technologies. Any projects planned or currently in construction, particularly significant capital projects, may be subject to risks including, but not limited to, impact on costs from schedule delays, risk of cost overruns, ensuring compliance with operating and environmental requirements and other events within or beyond the Company's control. The Company's projects may also require approvals and permits at the federal, provincial, state, regional and local levels. There is no assurance that Emera will be able to obtain the necessary project approvals or applicable permits or receive regulatory approval to recover the costs in rates.

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Some of the Company's assets are located on land owned by third parties, including Indigenous Peoples, and may be subject to land claims. Present or future assets may be located on lands that have been used for traditional purposes and therefore subject to specific consultations, consents, or conditions for development or operation. If the Company's rights to locate and operate its assets on any such lands are subject to expiry or become invalid, it may incur material costs to renew rights or obtain such rights. If reasonable terms for land-use rights cannot be negotiated, the Company may incur significant costs to remove and relocate its assets and restore the land. Additional costs incurred could cause projects to be uneconomical to proceed with.

Emera manages these project development and land use rights risks by deploying robust project and risk management approaches, led by teams with extensive experience in large projects. The Company consults with Indigenous Peoples in obtaining approvals, constructing, maintaining and operating such facilities, consistent with laws and public policy frameworks. Emera maintains relationships through on-going communications with stakeholders, including Indigenous Peoples, landowners and governments.

### **Counterparty Risk**

Emera is exposed to risk related to its reliance on certain key partners, suppliers, and customers, any of which may endure financial challenges resulting from commodity price and market volatility, economic instability or adversity, adverse political or regulatory changes and other causes which may cause or contribute to such parties' insolvency, bankruptcy, restructuring or default on their contractual obligations to Emera. Emera is also exposed to potential losses related to amounts receivable from customers, energy marketing collateral deposits and derivative assets due to a counterparty's non-performance under an agreement.

Emera manages this counterparty risk through due diligence and third-party risk assessment processes prior to signing contracts, contractual rights and remedies, regulatory frameworks, and by monitoring significant developments with its customers, partners and suppliers. The Company also manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments may be conducted on new customers and counterparties, and deposits or collateral may be requested on certain accounts. There is no assurance that management strategies will be effective, and significant counterparty defaults could have a material effect on the Company.

### **Country Risk**

The majority of Emera's earnings are from outside of Canada, mostly concentrated in the United States. Emera's investments are currently in regions where political and economic risks are considered by the Company to be acceptable. For more information, refer to the 'Regulatory and Political Risk' and 'General Economic Risk' sections above. Emera's operations in some countries may be subject to changes in economic growth, restrictions on the repatriation of income or capital exchange controls, inflation, the effect of global health, safety and environmental matters, including climate change, or economic conditions and market conditions, and change in financial policy and availability of credit. The Company mitigates this risk through a rigorous approval process for investment, and by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available in all affiliates.

### **Commodity Price Risk**

The Company's utility fuel supply is subject to commodity price risk. In addition, Emera Energy is subject to commodity price risk through its portfolio of commodity contracts and arrangements.

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The Company manages this risk through established processes and practices to identify, monitor, report and mitigate these risks. These include the Company's commercial arrangements, such as the combination of supply and purchase agreements, asset management agreements, pipeline transportation agreements, and financial hedging instruments. In addition, its credit policies, counterparty credit assessments, market and credit position reporting, and other risk management and reporting practices, are also used to manage and mitigate this risk.

#### *Regulated Utilities*

The Company's utility fuel supply is exposed to broader global conditions, which may include impacts on delivery reliability and price, despite contracted terms. Supply and demand dynamics in fuel markets can be affected by a wide range of factors which are difficult to predict and may change rapidly, including but not limited to, currency fluctuations, changes in global economic conditions, natural disasters, transportation or production disruptions, and geo-political risks, such as political instability, conflicts, changes to international trade agreements, trade sanctions or embargos. The Company seeks to manage this risk using financial hedging instruments and physical contracts and through contractual protection with counterparties, where applicable.

The majority of Emera's regulated electric and gas utilities have adopted and implemented fuel adjustment mechanisms and purchased gas adjustment mechanisms respectively, which further helps manage commodity price risk, as the regulatory framework for the Company's rate-regulated subsidiaries permits the recovery of prudently incurred fuel and gas costs. There is no assurance that such mechanisms and regulatory frameworks will continue to exist in the future. Prolonged and substantial increases in fuel prices could result in decreased rate affordability, increased risk of recovery of costs or regulatory assets, and/or negative impacts on customer consumption patterns and sales.

#### *Emera Energy Marketing and Trading*

Emera Energy has employed further measures to manage commodity risk. The majority of Emera Energy's portfolio of electricity and gas marketing and trading contracts and, in particular, its natural gas asset management arrangements, are contracted on a back-to-back basis, avoiding any material long or short commodity positions. However, the portfolio is subject to commodity price risk, particularly with respect to basis point differentials between relevant markets in the event of an operational issue or counterparty default. Changes in commodity prices can also result in increased collateral requirements associated with physical contracts and financial hedges, resulting in higher liquidity requirements and increased costs to the business.

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.

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## Future Employee Benefit Plan Performance and Funding Risk

Emera subsidiaries have both defined benefit and defined contribution employee pension plans that cover their employees and retirees. All defined benefit plans are closed to new entrants, except for the TECO Energy Group Retirement Plan. The cost of providing these benefit plans varies depending on plan provisions, interest rates, inflation, investment performance and actuarial assumptions concerning the future. Actuarial assumptions include earnings on plan assets, discount rates (interest rates used to determine funding levels, contributions to the plans and the pension and post-retirement liabilities) and expectations around future salary growth, inflation and mortality. Three of the largest drivers of cost are investment performance, interest rates and inflation, which are affected by global financial and capital markets. Depending on future interest rates and future inflation and actual versus expected investment performance, Emera could be required to make larger contributions in the future to fund these plans, which could adversely affect Emera's cash flows, financial condition and operations.

Each of Emera's employee defined benefit pension plans are managed according to an approved investment policy and governance framework. Emera employs a long-term approach with respect to asset allocation and each investment policy outlines the level of risk which the Company is prepared to accept with respect to the investment of the pension funds in achieving both the Company's fiduciary and financial objectives. Studies are routinely undertaken approximately every five years with the objective that the plans' asset allocations are appropriate for meeting Emera's long-term pension objectives.

## Labour Risk

Emera's ability to deliver service to its customers and to execute its growth plan depends on attracting, developing and retaining a skilled workforce. Utilities are faced with demographic challenges related to trades, technical staff and engineers with an increasing number of employees expected to retire over the next several years. Failure to attract, develop and retain an appropriately qualified workforce could adversely affect the Company's operations and financial results. Emera seeks to manage this risk through maintaining competitive compensation programs, a dedicated talent acquisition team, human resources programs and practices, including ethics and diversity training, employee engagement surveys, succession planning for key positions and apprenticeship programs.

Approximately 32 per cent of Emera's labour force is represented by unions and subject to collective labour agreements. The inability to maintain or negotiate future agreements on acceptable terms could result in higher labour costs and work disruptions, which could adversely affect service to customers and have an adverse effect on the Company's earnings, cash flow and financial position. Emera seeks to manage this risk through ongoing discussions and working to maintain positive relationships with local unions. The Company maintains contingency plans in each of its operations to manage and reduce the effect of any potential labour disruption.

## IT Risk

Emera relies on various IT systems to manage operations. This subjects Emera to inherent costs and risks associated with maintaining, upgrading, replacing and changing these systems. This includes impairment of its IT, potential disruption of internal control systems, substantial capital expenditures, demands on management time and other risks of delays, difficulties in upgrading existing systems, transitioning to new systems or integrating new systems into its current systems. Emera's digital transformation strategy, including investment in infrastructure modernization and customer focused technologies, is driving increased investment in IT solutions, resulting in increased project risks associated with the implementation of these solutions.

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Emera manages these risks through IT asset lifecycle planning and management, governance, internal auditing and testing of systems, and executive oversight. Employees with extensive subject matter expertise assist in risk identification and mitigation, project management, implementation, change management and training. System resiliency, formal disaster recovery and backup processes, combined with critical incident response practices, table-top exercises, and simulations, help mitigate operational disruptions.

### **Income Tax Risk**

The computation of the Company's provision for income taxes is impacted by changes in tax legislation in Canada, the United States and the Caribbean. Any such changes could affect the Company's future earnings, cash flows, and financial position. The value of Emera's existing deferred tax assets and liabilities are determined by existing tax laws and could be negatively impacted by changes in laws. Emera monitors the status of existing tax laws to ensure that changes impacting the Company are appropriately reflected in the Company's tax compliance filings and financial results.

### **System Operating and Maintenance Risks**

The safe and reliable operation of electric generation and electric and natural gas transmission and distribution systems is critical to Emera's operations. There are a variety of hazards and operational risks inherent in operating electric utilities and natural gas transmission and distribution pipelines. Electric generation, transmission and distribution operations can be impacted by risks such as mechanical failures, supply chain issues impacting timely access to critical equipment, activities of third parties, terrorism, cyberattacks, damage to facilities, solar panels and infrastructure caused by hurricanes, storms, falling trees, lightning strikes, floods, fires and other natural disasters. Natural gas pipeline operations can also be impacted by risks such as leaks, explosions, mechanical failures, activities of third parties, terrorism, cyberattacks, and damage to the pipeline facilities and equipment caused by hurricanes, storms, floods, fires and other natural disasters. Refer to 'Global Climate Change Risk' and 'Weather Risk'. Electric utility and natural gas transmission and distribution pipeline operation interruption could negatively affect revenue, earnings, and cash flows as well as customer and public confidence, and public safety.

Emera manages these risks by investing in a highly skilled workforce, operating prudently, preventative maintenance, safety and operations management systems, third-party risk program, and making effective capital investments. Insurance, warranties, or recovery through regulatory mechanisms may not cover any or all these losses, which could adversely affect the Company's results of operations and cash flows.

### *Fuel Supply Disruptions*

Emera's electric and natural gas utilities are also exposed to the risk of fuel supply chain disruptions, both within and outside their service territories, which may be caused by severe weather or natural disasters. This may also be caused by damage to, operational issues with, terrorist or cyberattacks on, third party fuel production, storage, pipeline, and distribution facilities. The risk of fuel supply disruptions is managed through contractual protections, maintaining a diversity of fuel suppliers and transportation contracts, and contracting for access to third-party storage facilities. Significant unanticipated fuel supply disruptions, such as those which arose from Winter Storm Uri in February 2021, could result in increased exposure to commodity price risk for Emera's regulated electric and gas utilities and Emera Energy, and these could have adverse effects on service to utility customers and on the Company's reputation, earnings, cash flow and financial position.

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## Uninsured Risk

Emera and its subsidiaries maintain insurance to cover accidental loss suffered to its facilities and to provide indemnity in the event of liability to third parties. This is consistent with Emera's risk management policies. Certain facilities, in particular coal and other thermal generation, may, over time, become more difficult (or uneconomic) to insure as a result of the impact of global climate change. Refer to 'Global Climate Change Risk - Markets'. There are certain elements of Emera's operations which are not insured. These include a significant portion of its electric utilities' transmission and distribution assets, as is customary in the industry. The cost of this coverage is not economically viable. In addition, Emera accepts deductibles and self-insured retentions under its various insurance policies. Insurance is subject to coverage limits as well as time sensitive claims discovery and reporting provisions and there can be no assurance that the types of liabilities or losses that may be incurred by the Company and its subsidiaries will be covered by insurance.

The occurrence of significant uninsured claims, claims in excess of the insurance coverage limits maintained by Emera and its subsidiaries, or claims that fall within a significant self-insured retention could have a material adverse effect on Emera's results of operations, cash flows and financial position, if regulatory recovery is not available.

The Company mitigates its uninsured risk by ensuring insurance limits align with risk exposures, and for uninsured assets and operations, that appropriate risk assessments and mitigation measures are in place. The regulatory framework for the Company's rate-regulated subsidiaries permits the recovery of prudently incurred costs, including uninsured losses.

## RISK MANAGEMENT INCLUDING FINANCIAL INSTRUMENTS

Emera's risk management policies and procedures provide a framework through which management monitors various risk exposures. The risk management policies and practices are overseen by the Board of Directors. The Company has established a number of processes and practices to identify, monitor, report on and mitigate material risks to the Company. This includes establishment of the ERMC, whose responsibilities include preparing an updated risk dashboard and heat map presented at regular meetings of the Board's Risk and Sustainability Committee. Furthermore, a corporate team independent from operations is responsible for tracking and reporting on market and credit risks.

The Company manages its exposure to normal operating and market risks relating to commodity prices, FX, interest rates and share prices through contractual protections with counterparties where practicable, and by using financial instruments consisting mainly of FX forwards and swaps, interest rate options and swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. These physical and financial contracts are classified as held-for-trading ('HFT'). Collectively, these contracts and financial instruments are considered derivatives.

The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales ('NPNS') exception. Physical contracts that meet the NPNS exception are not recognized on the balance sheet; these contracts are recognized in income when they settle. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company's business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty creditworthy. The Company continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met.

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Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the change in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value with any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.

Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates. Tampa Electric has no derivatives related to hedging as a result of a FPSC approved five-year moratorium on hedging of natural gas purchases which ended on December 31, 2022. Tampa Electric's moratorium on hedging of natural gas purchases will continue through December 31, 2024, as a result of Tampa Electric's 2021 rate case settlement agreement.

Derivatives that do not meet any of the above criteria are designated as HFT, with changes in fair value normally recorded in net income of the period. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply.

#### Derivative Assets and Liabilities Recognized on the Balance Sheet

| As at millions of dollars | December 31 2022 | December 31 2021 |
| --- | --- | --- |
| Regulatory Deferral: |  |  |
| Derivative instrument assets (1) | $238 | $237 |
| Derivative instrument liabilities (2) | (25) | (20) |
| Regulatory assets (1) | 30 | 23 |
| Regulatory liabilities (2) | (230) | (241) |
| Net asset (liability) | $13 | $(1) |
| HFT Derivatives: |  |  |
| Derivative instrument assets (1) | $153 | $53 |
| Derivatives instruments liabilities (2) | (1,025) | (662) |
| Net liability | $(872) | $(609) |
| Other Derivatives: |  |  |
| Derivative instrument assets (1) | $5 | $11 |
| Derivatives instruments liabilities (2) | (28) | - |
| Net asset (liability) | $(23) | $11 |

(1) Current and other assets.

(2) Current and long-term liabilities.

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## Realized and Unrealized Gains (Losses) Recognized in Net Income

| For the millions of dollars | Year ended December 31 |  |
| --- | --- | --- |
|  | 2022 | 2021 |
| Regulatory Deferral: |  |  |
| Regulated fuel for generation and purchased power (1) | $210 | $34 |
| HFT Derivatives: |  |  |
| Non-regulated operating revenues | $64 | $(138) |
| Other Derivatives: |  |  |
| OM&G | $(22) | $26 |
| Other income, net | (24) | 3 |
| Net gains (losses) | $(46) | $29 |
| Total net gains (losses) | $228 | $(75) |

(1) Realized gains (losses) on derivative instruments settled and consumed in the period, hedging relationships that have been terminated or the hedged transaction is no longer probable. Realized gains (losses) recorded in inventory will be recognized in 'Regulated fuel for generation and purchased power' when the hedged item is consumed.

As of December 31, 2022, the unrealized gain in AOCI was $16 million, net of tax (2021 - $18 million, net of tax). For the year ended December 31, 2022, unrealized gains of $2 million (2021 - $1 million), have been reclassified into interest expense.

## DISCLOSURE AND INTERNAL CONTROLS

Management is responsible for establishing and maintaining adequate disclosure controls and procedures ('DC&P') and internal control over financial reporting ('ICFR'), as defined in National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings ('NI 52-109'). The Company's internal control framework is based on the criteria published in the Internal Control - Integrated Framework (2013), a report issued by the Committee of Sponsoring Organizations ('COSO') of the Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer, evaluated the design and effectiveness of the Company's DC&P and ICFR as at December 31, 2022 to provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.

Management recognizes the inherent limitations in internal control systems, no matter how well designed. Control systems determined to be appropriately designed can only provide reasonable assurance with respect to the reliability of financial reporting and may not prevent or detect all misstatements.

There were no changes in the Company's ICFR, during the year ended December 31, 2022, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

## CRITICAL ACCOUNTING ESTIMATES

The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations ('ARO'), and valuation of financial instruments. Management evaluates the Company's estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise.

56

## Rate Regulation

The rate-regulated accounting policies of Emera's rate-regulated subsidiaries and regulated equity investments are subject to examination and approval by their respective regulators and may differ from the accounting policies of non-rate-regulated companies. Differences occur when regulators render their decisions on rate applications or other matters, and generally involve a difference in the timing of revenue and expense recognition. The accounting for these items is based on expectations of the future actions of the regulators. Assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital, and the timing and amount of assets to be recovered. The application of regulatory accounting guidance is a critical accounting policy as a change in these assumptions may result in a material impact on reported assets, liabilities and the results of operations.

As at December 31, 2022, the Company has recorded $3,620 million (2021 - $2,566 million) of regulatory assets and $2,273 million (2021 - $2,055 million) of regulatory liabilities.

## Accumulated Reserve - Cost of Removal

Tampa Electric, PGS, NMGC and NSPI recognize non-ARO costs of removal ('COR') as regulatory liabilities. The non-ARO COR represent estimated funds received from customers through depreciation rates to cover future COR of PP&E upon retirement that are not legally required. The companies accrue for COR over the life of the related assets based on depreciation studies approved by their respective regulators. The costs are estimated based on historical experience and future expectations, including expected timing and estimated future cash outlays. As at December 31, 2022, the balance of the Accumulated reserve - COR within regulatory liabilities was $895 million (2021 - $819 million).

## Pension and Other Post-Retirement Employee Benefits

The Company provides post-retirement benefits to employees, including defined benefit pension plans. The cost of providing these benefits is dependent upon many factors that result from actual plan experience and assumptions of future expectations.

The accounting related to employee post-retirement benefits is a critical accounting estimate. Changes in the estimated benefit obligation, affected by employee demographics, including age, compensation levels, employment periods, contribution levels and earnings, could have a material impact on reported assets, liabilities, accumulated other comprehensive income and results of operations. Changes in key actuarial assumptions, including anticipated rates of return on plan assets and discount rates used in determining the accrued benefit obligation and benefit costs, could change annual funding requirements. This could have a significant impact on the Company's annual earnings and cash requirements.

The pension plan assets are comprised primarily of equity and fixed income investments. Fluctuations in actual equity market returns and changes in interest rates may result in changes to pension costs in future periods.

The Company's accounting policy is to amortize the net actuarial gain or loss that exceeds 10 per cent of the greater of the projected benefit obligation / accumulated post-retirement benefit obligation ('PBO') and the market-related value of assets, over active plan members' average remaining service period. For the largest plans this is currently 8.3 years (8.7 years for 2022 benefit cost) for the Canadian plans and a weighted average of 11.4 years for the United States plans. The Company's use of smoothed asset values reduces volatility related to the amortization of actuarial investment experience. As a result, the main cause of volatility in reported pension cost is the discount rate used to determine the PBO.

57

The discount rate used to determine benefit costs is based on the yield of high quality long-term corporate bonds in each operating entity's country and is determined with reference to bonds which have the same duration as the PBO as at January 1 of the fiscal year. The following table shows the discount rate for benefit cost purposes and the expected return on plan assets for each plan:

|  | 2022 |  | 2021 |  |
| --- | --- | --- | --- | --- |
|  | Discount rate for benefit cost purposes | Expected return on plan assets | Discount rate for benefit cost purposes | Expected return on plan assets |
| TECO Energy Group Retirement Plan | 2.78% | 6.50% | 2.38% | 6.70% |
| TECO Energy Group Supplemental Executive Retirement Plan (1) | 2.35/5.33% | N/A | 1.84% | N/A |
| TECO Energy Group Benefit Restoration Plan (1) | 2.27/4.19/5.48% | N/A | 1.71% | N/A |
| TECO Energy Post-retirement Health and Welfare Plan | 2.84% | N/A | 2.47% | N/A |
| New Mexico Gas Company Retiree Medical Plan | 2.85% | 1.50% | 2.49% | 4.00% |
| NSPI | 3.25%, 3.48% | 5.75% | 2.59%, 2.85% | 5.25% |
| GBPC Salaried | 5.75% | 6.00% | 4.25% | 6.00% |
| GBPC Union | 5.75% | 5.35% | 5.65% | 5.65% |

(1) The discount rate and expected return on assets for benefit cost purposes is updated throughout the year as special events occur, such as settlements and curtailments.

Based on management's estimate, the reported benefit cost for defined benefit and defined contribution plans was $64 million in 2022 (2021 - $85 million). The reported benefit cost is impacted by numerous assumptions, including the discount rate and asset return assumptions. A 0.25 per cent change in the discount rate and asset return assumptions would have had +/- impact on the 2022 benefit cost of $0.5 million and $1 million respectively (2021 - $1 million and $3 million).

#### Unbilled Revenue

Electric and gas revenues are billed on a systematic basis over a one or two-month period for NSPI and a one-month period for other Emera utilities. At the end of each month, the Company must make an estimate of energy delivered to customers since the date their meter was last read and determine related revenues earned but not yet billed. The unbilled revenue is estimated based on several factors, including current month's generation, estimated customer usage by class, weather, line losses, inter-period changes to customer classes and applicable customer rates. Based on the extent of estimates included in the determination of unbilled revenue, actual results may differ from the estimate. At December 31, 2022, unbilled revenues totalled $424 million (2021 - $318 million) on total regulated operating revenues of $7,154 million (2021 - $5,926 million).

#### Property, Plant and Equipment

PP&E represents 58 per cent of total assets on the Company's balance sheet and include the generation, transmission and distribution, and other assets of the Company.

Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each category. The service lives of regulated PP&E are determined based on depreciation studies and require appropriate regulatory approval. Due to the magnitude of the Company's PP&E, changes in estimated depreciation rates can have a material impact on depreciation expense and accumulated depreciation.

Depreciation expense was $927 million for the year ended December 31, 2022 (2021 - $877 million).

58

## Goodwill Impairment Assessments

Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated fair values of identifiable assets acquired, and liabilities assumed at the acquisition date. Goodwill is carried at initial cost less any write-down for impairment and is adjusted for the impact of foreign exchange. Under the applicable accounting guidance, goodwill is subject to assessment for impairment at the reporting unit level annually, or if an event or change in circumstances indicates that the fair value of a reporting unit may be below its carrying value. Application of the goodwill impairment test requires management judgment on significant assumptions and estimates. When assessing goodwill for impairment, the Company has the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. In performing a qualitative assessment management considers, among other factors, macroeconomic conditions, industry and market considerations and overall financial performance.

If the Company performs the qualitative assessment and determines that it is more likely than not that its fair value is less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a quantitative test is performed. The quantitative test compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, an impairment loss is recorded. Significant assumptions used in estimating the fair value include discount and growth rates, rate case assumptions including future cost of capital, valuation of the reporting units' net operating loss ('NOL') and projected operating and capital cash flows. Adverse changes in these assumptions could result in a future material impairment of the goodwill assigned to Emera's reporting units.

As of December 31, 2022, $6,009 million of Emera's goodwill represents the excess of the acquisition purchase price for TECO Energy (Tampa Electric, PGS and NMGC reporting units) over the fair values assigned to identifiable assets acquired and liabilities assumed. In Q4 2022, qualitative assessments were performed for Tampa Electric and PGS given the significant excess of fair value over carrying amounts calculated during the last quantitative test in Q4 2019. Management concluded it was more likely than not that the fair value of these reporting units exceeded their respective carrying amounts, including goodwill. As such, no quantitative testing was required. For the NMGC reporting unit, Emera elected to bypass a qualitative assessment and performed a quantitative impairment assessment using a combination of the income and market approach. This assessment estimated that the fair value of the NMGC reporting unit exceeded its carrying amount, including goodwill. As a result of this assessment, no impairment charges were recognized.

In Q4 2022, the Company elected to bypass a qualitative assessment and performed a quantitative impairment assessment for GBPC, using the income approach, as this reporting unit is sensitive to changes in assumptions due to limited excess of fair value over the carrying value, including goodwill. Although the cash flows of GBPC have not changed significantly compared to previous periods, it was determined that the carrying value, including goodwill, exceeded the fair value, due to an increase in discount rates. The discount rate for the reporting unit was negatively impacted by changes in the macroeconomic environment, including the risk-free rate assumption. As a result of this assessment, a goodwill impairment charge of $73 million was recorded in 2022, reducing the GBPC goodwill balance to nil as at December 31, 2022. No impairment was recorded in 2021. For further detail, refer to note 22.

As of December 31, 2022, the Company had goodwill with a total carrying amount of $6,012 million (December 31, 2021 - $5,696 million). The change in the carrying value of goodwill from 2021 to 2022 was a result of the effect of the FX translation of Emera's foreign affiliates, partially offset by the GBPC impairment.

59

## Long-Lived Assets Impairment Assessments

In accordance with accounting guidance for long-lived assets, the Company assesses whether there has been an impairment of long-lived assets and intangibles when a triggering event occurs, such as a significant market disruption or the sale of a business. The assessment involves comparing the undiscounted expected future cash flows, to the carrying value of the asset. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset over its estimated fair value.

The Company believes accounting estimates related to asset impairments are critical estimates, as they are highly susceptible to change and the impact of an impairment on reported assets and earnings could be material. Management is required to make assumptions based on expectations regarding the results of operations for significant/indefinite future periods and the current and expected market conditions in such periods. Markets can experience significant uncertainties. Estimates based on the Company's assumptions relating to future results of operations or other recoverable amounts are based on a combination of historical experience, fundamental economic analysis, observable market activity and independent market studies. The Company's expectations regarding uses and holding periods of assets are based on internal long-term budgets and projections, which consider external factors and market forces, as of the end of each reporting period. Assumptions made by management are consistent with generally accepted industry approaches and assumptions used for valuation and pricing activities.

As at December 31, 2022, there were no indications of impairment of Emera's long-lived assets. No impairment charges were recognized in either 2022 or 2021.

## Income Taxes

Income taxes are determined based on the expected tax treatment of transactions recorded in the consolidated financial statements. In determining income taxes, tax legislation is interpreted in a variety of jurisdictions, the likelihood that deferred tax assets will be realized is assessed and assumptions about the expected timing of the reversal of deferred tax assets and liabilities are made. Uncertainty associated with application of tax statutes and regulations and the outcomes of tax audits and appeals, requires that judgments and estimates be made in the accrual process and in the calculation of effective tax rates. Only income tax benefits that meet the 'more likely than not' threshold may be recognized or continue to be recognized. Unrecognized tax benefits are evaluated quarterly and changes are recorded based on new information, including issuance of relevant guidance by the courts or tax authorities and developments in examinations of the Company's tax returns.

The Company believes the accounting estimates related to income taxes are critical estimates. The realization of deferred tax assets is dependent upon the generation of sufficient taxable income, both operating and capital, in future periods. A change in the estimated valuation allowance could have a material impact on reported assets and results of operations. Administrative actions of the tax authorities, changes in tax law or regulation, and the uncertainty associated with the application of tax statutes and regulations, could change the Company's estimate of income taxes, including the potential for elimination or reduction of the Company's ability to realize tax benefits and to utilize deferred tax assets.

## Asset Retirement Obligations

Measurement of the fair value of AROs requires the Company to make reasonable estimates concerning the method and timing of settlement associated with the legally obligated costs. There are uncertainties in estimating future asset-retirement costs due to potential events, such as changing legislation or regulations, and advances in remediation technologies. Emera has AROs associated with the remediation of generation, transmission, distribution and pipeline assets.

60

An ARO represents the fair value of the estimated cash flows necessary to discharge the future obligation using the Company's credit-adjusted risk-free rate. The amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports, prior experience, estimated useful lives, and governmental regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long-lived asset. Over time, the liability is accreted to its estimated future value. Accretion expense is included as part of 'Depreciation and amortization expense'. Any accretion expense not yet approved by the regulator is recorded in 'PP&E' and included in the next depreciation study. Accordingly, changes to the ARO or cost recognition attributable to changes in the factors discussed above, should not impact the results of operations of the Company.

Some of the Company's transmission and distribution assets may have conditional AROs which are not recognized in the consolidated financial statements as the fair value of these obligations could not be reasonably estimated given there is insufficient information to do so. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Management monitors these obligations and a liability is recognized at fair value when an amount can be determined.

As at December 31, 2022, AROs recorded on the balance sheet were $174 million (2021 - $174 million). The Company estimates the undiscounted amount of cash flow required to settle the obligations is approximately $429 million (2021 - $422 million), which will be incurred between 2023 and 2061. The majority of these costs will be incurred between 2028 and 2050.

#### **Financial Instruments**

The Company is required to determine the fair value of all derivatives except those which qualify for the normal purchase, normal sale exception. Fair value is the price that would be received for the sale of an asset or paid to transfer a liability in an orderly arms-length transaction between market participants at the measurement date. Fair value measurements are required to reflect assumptions that market participants would use in pricing an asset or liability based on the best available information, including the risks inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to the model.

#### **Level Determinations and Classifications**

The Company uses Level 1, 2, and 3 classifications in the fair value hierarchy. The fair value measurement of a financial instrument is included in only one of the three levels and is based on the lowest level input significant to the derivation of the fair value. Fair values are determined, directly or indirectly, using inputs that are observable for the asset or liability. Only in limited circumstances does the Company enter into commodity transactions involving non-standard features where market observable data is not available or have contract terms that extend beyond five years.

61

# CHANGES IN ACCOUNTING POLICIES AND PRACTICES

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

## Facilitation of the Effects of Reference Rate Reform on Financial Reporting

The Company adopted Accounting Standard Update ('ASU') 2022-06, *Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848* in Q4 2022. The update extends the period of time preparers can utilize the reference rate reform relief guidance issued under ASU 2020-04, which was adopted by the Company in Q4 2020. The guidance in ASU 2022-06 was effective as of the date of issuance and entities may elect to apply the guidance prospectively through to December 31, 2024. The Company has applied the guidance permitted by ASU 2020-04 to certain debt agreements that were amended during the current period. The Company's transition from reference rates will not have a material impact on the consolidated financial statements.

## Future Accounting Pronouncements

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

## SUMMARY OF QUARTERLY RESULTS

| For the quarter ended millions of dollars (except per share amounts) | Q4 2022 | Q3 2022 | Q2 2022 | Q1 2022 | Q4 2021 | Q3 2021 | Q2 2021 | Q1 2021 |
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Operating revenues | $2,358 | $1,835 | $1,380 | $2,015 | $1,868 | $1,148 | $1,137 | $1,612 |
| Net income (loss) attributable to common shareholders | $483 | $167 | $(67) | $362 | $324 | $(70) | $(17) | $273 |
| Adjusted net income | $249 | $203 | $156 | $242 | $168 | $175 | $137 | $243 |
| EPS - basic | $1.80 | $0.63 | $(0.25) | $1.38 | $1.24 | $(0.27) | $(0.07) | $1.08 |
| EPS - diluted | $1.80 | $0.63 | $(0.25) | $1.38 | $1.20 | $(0.27) | $(0.07) | $1.08 |
| Adjusted EPS - basic | $0.93 | $0.76 | $0.59 | $0.92 | $0.64 | $0.68 | $0.54 | $0.96 |

Quarterly operating revenues and adjusted net income are affected by seasonality. The first quarter provides strong earnings contributions due to a significant portion of the Company's operations being in northeastern North America, where winter is the peak electricity usage season. The third quarter provides strong earnings contributions due to summer being the heaviest electric consumption season in Florida. Seasonal and other weather patterns, as well as the number and severity of storms, can affect demand for energy and the cost of service. Quarterly results could also be affected by items outlined in the 'Significant Items Affecting Earnings' section.

62

## Exhibit 99.3

# **EMERA INCORPORATED**  
**Consolidated**  
**Financial Statements**  
**December 31, 2022 and 2021**

1

# MANAGEMENT REPORT

## Management's Responsibility for Financial Reporting

The accompanying consolidated financial statements of Emera Incorporated and the information in this annual report are the responsibility of management and have been approved by the Board of Directors ('Board').

The consolidated financial statements have been prepared by management in accordance with United States Generally Accepted Accounting Principles. When alternative accounting methods exist, management has chosen those it considers most appropriate in the circumstances. In preparation of these consolidated financial statements, estimates are sometimes necessary when transactions affecting the current accounting period cannot be finalized with certainty until future periods. Management represents that such estimates, which have been properly reflected in the accompanying consolidated financial statements, are based on careful judgments and are within reasonable limits of materiality. Management has determined such amounts on a reasonable basis in order to ensure that the consolidated financial statements are presented fairly in all material respects. Management has prepared the financial information presented elsewhere in the annual report and has ensured that it is consistent with that in the consolidated financial statements.

Emera Incorporated maintains effective systems of internal accounting and administrative controls, consistent with reasonable cost. Such systems are designed to provide reasonable assurance that the financial information is reliable and accurate, and that Emera Incorporated's assets are appropriately accounted for and adequately safeguarded.

The Board is responsible for ensuring that management fulfils its responsibilities for financial reporting and is ultimately responsible for reviewing and approving the consolidated financial statements. The Board carries out this responsibility principally through its Audit Committee.

The Audit Committee is appointed by the Board, and its members are directors who are not officers or employees of Emera Incorporated. The Audit Committee meets periodically with management, as well as with the internal auditors and with the external auditors, to discuss internal controls over the financial reporting process, auditing matters and financial reporting issues, to satisfy itself that each party is properly discharging its responsibilities, and to review the annual report, the consolidated financial statements and the external auditors' report. The Audit Committee reports its findings to the Board for consideration when approving the consolidated financial statements for issuance to the shareholders. The Audit Committee also considers, for review by the Board and approval by the shareholders, the appointment of the external auditors.

The consolidated financial statements have been audited by Ernst & Young LLP, the external auditors, in accordance with Canadian Generally Accepted Auditing Standards and with the standards of the Public Company Accounting Oversight Board. Ernst & Young LLP has full and free access to the Audit Committee.

February 23, 2023

President and Chief Executive Officer

Chief Financial Officer

2

# Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Emera Incorporated

## Opinion on the Consolidated Financial Statements

We have audited the accompanying Consolidated Balance Sheets of Emera Incorporated (the 'Company') as of December 31, 2022 and 2021, the related Consolidated Statements of Income, Consolidated Statements of Comprehensive Income, Consolidated Statements of Changes in Equity and Consolidated Statements of Cash Flows for the years then ended, and the related notes (collectively referred to as the 'consolidated financial statements'). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2022 and 2021, and the consolidated results of its operations and its consolidated cash flows for each of the two years in the period ended December 31, 2022, in conformity with United States generally accepted accounting principles.

## Basis for Opinion

These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ('PCAOB') and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

## Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

3

### ***Accounting for the effects of rate regulation***

#### *Description of the Matter*

As disclosed in note 7 of the consolidated financial statements, the Company has $3.6 billion in regulatory assets and $2.3 billion in regulatory liabilities. The Company's rate-regulated subsidiaries are subject to regulation by various federal, state and provincial regulatory authorities in the geographic regions in which they operate. The regulatory rates are designed to recover the prudently incurred costs of providing the regulated products or services and provide a reasonable return on the equity invested or assets, as applicable. In addition to regulatory assets and liabilities, rate regulation impacts multiple financial statement line items, including, but not limited to, property, plant and equipment ('PP&E'), operating revenues and expenses, income taxes, and depreciation expense.

Auditing the impact of rate regulation on the Company's financial statements is complex and highly judgmental due to the significant judgments made by the Company to support its accounting and disclosure for regulatory matters when final regulatory decisions or orders have not yet been obtained or when regulatory formulas are complex. There is also subjectivity involved in assessing the potential impact of future regulatory decisions on the financial statements. Although the Company expects to recover costs from customers through rates, there is a risk that the regulator will not approve full recovery of the costs incurred. The Company's judgments include making an assessment of the probability of recovery of and return on costs incurred, of the potential disallowance of part of the cost incurred, or of the probable refund to customers through future rates.

#### *How We Addressed the Matter in Our Audit*

We performed audit procedures that included, amongst others, assessing the Company's evaluation of the probability of future recovery for regulatory assets, PP&E, and refund of regulatory liabilities by obtaining and reviewing relevant regulatory orders, filings, testimony, hearings and correspondence, and other publicly available information. For regulatory matters for which regulatory decisions or orders have not yet been obtained, we inspected the rate-regulated subsidiaries' filings for any evidence that might contradict the Company's assertions, and reviewed other regulatory orders, filings and correspondence for other entities within the same or similar jurisdictions to assess the likelihood of recovery in future rates based on the regulator's treatment of similar costs under similar circumstances. We obtained and evaluated an analysis from the Company and corroborated that analysis with letters from legal counsel, when appropriate, regarding cost recoveries or future changes in rates. We also assessed the methodology, accuracy and completeness of the Company's calculations of regulatory asset and liability balances based on provisions and formulas outlined in rate orders and other correspondence with the regulators. We evaluated the Company's disclosures related to the impacts of rate regulation.

### ***Fair value measurement of derivative financial instruments***

#### *Description of the Matter*

Held-for-trading ('HFT') derivative assets of $429 million and liabilities of $1,301 million, disclosed in note 15 to the consolidated financial statements, are measured at fair value. The Company recognized $64 million in realized and unrealized gains during the year with respect to HFT derivatives.

Auditing the Company's valuation of HFT derivatives is complex and highly judgmental due to the complexity of the contract terms and valuation models, and the significant estimation required in determining the fair value of the contracts. In determining the fair value of HFT derivatives, significant assumptions about future economic and market assumptions with uncertain outcomes are used, including third-party sourced forward commodity pricing

4

*How We Addressed
the Matter in Our
Audit*

curves based on illiquid markets, internally developed correlation factors and basis differentials. These assumptions have a significant impact on the fair value of the HFT derivatives.

We performed audit procedures that included, amongst others, reviewing executed contracts and agreements for the identification of inputs and assumptions impacting the valuation of derivatives. With the support of our valuation specialists, we assessed the methodology and mathematical accuracy of the Company's valuation models and compared the commodity pricing curves used by the Company to current market and economic data. For the forward commodity pricing curves, we compared the Company's pricing curves to independently sourced pricing curves. We also assessed the methodology and mathematical accuracy of the Company's calculations to develop correlation factors and basis differentials. In addition, we assessed whether the fair value hierarchy disclosures in note 16 to the consolidated financial statements were consistent with the source of the significant inputs and assumptions used in determining the fair value of derivatives.

/s/ Ernst & Young LLP
Chartered Professional Accountants

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

Halifax, Canada
February 23, 2023

5

# **Emera Incorporated**  
 **Consolidated Statements of Income**

| For the millions of dollars (except per share amounts) | Year ended December 31 |  |
| --- | --- | --- |
|  | 2022 | 2021 |
| Operating revenues |  |  |
| Regulated electric | $5,473 | $4,665 |
| Regulated gas | 1,681 | 1,261 |
| Non-regulated | 434 | (161) |
| Total operating revenues (note 6) | 7,588 | 5,765 |
| Operating expenses |  |  |
| Regulated fuel for generation and purchased power | 2,171 | 1,763 |
| Regulated cost of natural gas | 800 | 472 |
| Operating, maintenance and general expenses ('OM&G') | 1,596 | 1,368 |
| Provincial, state, and municipal taxes | 367 | 330 |
| Depreciation and amortization | 952 | 902 |
| Impairment charge (note 22) | 73 | - |
| Total operating expenses | 5,959 | 4,835 |
| Income from operations | 1,629 | 930 |
| Income from equity investments (note 8) | 129 | 143 |
| Other income, net (note 9) | 145 | 93 |
| Interest expense, net | 709 | 611 |
| Income before provision for income taxes | 1,194 | 555 |
| Income tax expense (recovery) (note 10) | 185 | (6) |
| Net income | 1,009 | 561 |
| Non-controlling interest in subsidiaries | 1 | 1 |
| Preferred stock dividends | 63 | 50 |
| Net income attributable to common shareholders | $945 | $510 |
| Weighted average shares of common stock outstanding (in millions) (note 12) |  |  |
| Basic | 266 | 257 |
| Diluted | 266 | 258 |
| Earnings per common share (note 12) |  |  |
| Basic | $3.56 | $1.98 |
| Diluted | $3.55 | $1.98 |
| Dividends per common share declared | $2.6775 | $2.5750 |

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

6

# **Emera Incorporated**
**Consolidated Statements of Comprehensive Income**

| For the millions of dollars | Year ended December 31 |  |
| --- | --- | --- |
|  | 2022 | 2021 |
| Net income | $1,009 | $561 |
| Other comprehensive income (loss), net of tax |  |  |
| Foreign currency translation adjustment (1) | 629 | (42) |
| Unrealized (losses) gains on net investment hedges (2) (3) | (97) | 5 |
| Cash flow hedges |  |  |
| Net derivative gains (4) | - | 18 |
| Less: reclassification adjustment for gains included in income | (2) | (1) |
| Net effects of cash flow hedges | (2) | 17 |
| Unrealized losses on available-for-sale investment | (1) | - |
| Net change in unrecognized pension and post-retirement benefit obligation (5) | 24 | 124 |
| Other comprehensive income (6) | 553 | 104 |
| Comprehensive income | 1,562 | 665 |
| Comprehensive income attributable to non-controlling interest | 1 | 1 |
| Comprehensive Income of Emera Incorporated | $1,561 | $664 |

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

1) Net of tax expense of $7 million for the year ended December 31, 2022 (2021 - $5 million expense).
2) The Company has designated $1.2 billion United States dollar (USD) denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in USD denominated operations.
3) Net of tax recovery of $6 million for the year ended December 31, 2022 (2021 - $1 million expense).
4) Net of tax recovery of $1 million for the year ended December 31, 2022 (2021 - $6 million expense).
5) Net of tax expense of $1 million for the year ended December 31, 2022 (2021 - $2 million expense).
6) Net of tax expense of $1 million for the year ended December 31, 2022 (2021 - $14 million expense).

7

## Consolidated Balance Sheets

| As at millions of dollars | December 31 2022 | December 31 2021 |
| --- | --- | --- |
| Assets |  |  |
| Current assets |  |  |
| Cash and cash equivalents | $310 | $394 |
| Restricted cash (note 32) | 22 | 23 |
| Inventory (note 14) | 769 | 538 |
| Derivative instruments (notes 15 and 16) | 296 | 195 |
| Regulatory assets (note 7) | 602 | 253 |
| Receivables and other current assets (note 18) | 2,897 | 1,733 |
|  | 4,896 | 3,136 |
| Property, plant and equipment ('PP&E'), net of accumulated depreciation and amortization of $9,574 and $8,739, respectively (note 20) | 22,996 | 20,353 |
| Other assets |  |  |
| Deferred income taxes (note 10) | 237 | 295 |
| Derivative instruments (notes 15 and 16) | 100 | 106 |
| Regulatory assets (note 7) | 3,018 | 2,313 |
| Net investment in direct finance and sales type leases (note 19) | 604 | 503 |
| Investments subject to significant influence (note 8) | 1,418 | 1,382 |
| Goodwill (note 22) | 6,012 | 5,696 |
| Other long-term assets (note 32) | 461 | 460 |
|  | 11,850 | 10,755 |
| Total assets | $39,742 | $34,244 |
| Liabilities and Equity |  |  |
| Current liabilities |  |  |
| Short-term debt (note 23) | $2,726 | $1,742 |
| Current portion of long-term debt (note 25) | 574 | 462 |
| Accounts payable | 2,025 | 1,485 |
| Derivative instruments (notes 15 and 16) | 888 | 533 |
| Regulatory liabilities (notes 7 and 32) | 495 | 290 |
| Other current liabilities (note 24) | 579 | 366 |
|  | 7,287 | 4,878 |
| Long-term liabilities |  |  |
| Long-term debt (note 25) | 15,744 | 14,196 |
| Deferred income taxes (note 10) | 2,196 | 1,868 |
| Derivative instruments (notes 15 and 16) | 190 | 149 |
| Regulatory liabilities (note 7) | 1,778 | 1,765 |
| Pension and post-retirement liabilities (note 21) | 281 | 370 |
| Other long-term liabilities (notes 8 and 26) | 825 | 868 |
|  | 21,014 | 19,216 |
| Equity |  |  |
| Common stock (note 11) | 7,762 | 7,242 |
| Cumulative preferred stock (note 28) | 1,422 | 1,422 |
| Contributed surplus | 81 | 79 |
| Accumulated other comprehensive income ('AOCI') (note 13) | 578 | 25 |
| Retained earnings | 1,584 | 1,348 |
| Total Emera Incorporated equity | 11,427 | 10,116 |
| Non-controlling interest in subsidiaries (note 29) | 14 | 34 |
| Total equity | 11,441 | 10,150 |
| Total liabilities and equity | $39,742 | $34,244 |

Commitments and contingencies (note 27)

Approved on behalf of the Board of Directors

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

Chair of the Board

President and Chief Executive Officer

8

# **Emera Incorporated**  
 **Consolidated Statements of Cash Flows**

| For the year ended December 31 | Year ended December 31 2022 | 2021 |
| --- | --- | --- |
| Operating activities |  |  |
| Net income | $1,009 | $561 |
| Adjustments to reconcile net income to net cash provided by operating activities: |  |  |
| Depreciation and amortization | 959 | 915 |
| Income from equity investments, net of dividends | (61) | (69) |
| Allowance for equity funds used during construction | (52) | (61) |
| Deferred income taxes, net | 152 | (37) |
| Net change in pension and post-retirement liabilities | (48) | (23) |
| Fuel adjustment mechanism ('FAM') | (162) | (166) |
| Net change in fair value of derivative instruments | 206 | 404 |
| Net change in regulatory assets and liabilities | (471) | (176) |
| Net change in capitalized transportation capacity | (445) | (107) |
| Impairment charge | 73 | - |
| Other operating activities, net | (13) | 96 |
| Changes in non-cash working capital (note 30) | (234) | (152) |
| Net cash provided by operating activities | 913 | 1,185 |
| Investing activities |  |  |
| Additions to PP&E | (2,596) | (2,359) |
| Other investing activities | 27 | 27 |
| Net cash used in investing activities | (2,569) | (2,332) |
| Financing activities |  |  |
| Change in short-term debt, net | 1,028 | (155) |
| Proceeds from short-term debt with maturities greater than 90 days | 544 | 640 |
| Repayment of short-term debt with maturities greater than 90 days | (680) | (377) |
| Proceeds from long-term debt, net of issuance costs | 784 | 2,554 |
| Retirement of long-term debt | (367) | (1,660) |
| Net proceeds under committed credit facilities | 511 | 82 |
| Issuance of common stock, net of issuance costs | 277 | 317 |
| Issuance of preferred stock, net of issuance costs (note 28) | - | 416 |
| Dividends on common stock | (472) | (443) |
| Dividends on preferred stock | (63) | (50) |
| Other financing activities | (7) | (13) |
| Net cash provided by financing activities | 1,555 | 1,311 |
| Effect of exchange rate changes on cash, cash equivalents, and restricted cash | 16 | (1) |
| Net increase (decrease) in cash, cash equivalents, and restricted cash | (85) | 163 |
| Cash, cash equivalents, and restricted cash, beginning of year | 417 | 254 |
| Cash, cash equivalents, and restricted cash, end of year | $332 | $417 |
| Cash, cash equivalents, and restricted cash consists of: |  |  |
| Cash | $302 | $237 |
| Short-term investments | 8 | 157 |
| Restricted cash | 22 | 23 |
| Cash, cash equivalents, and restricted cash | $332 | $417 |

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

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

9

# **Emera Incorporated**  
 **Consolidated Statements of Changes in Equity**

|  | Common Stock | Preferred Stock | Contributed Surplus | AOCI | Retained Earnings | Non- Controlling Interest | Total Equity |
| --- | --- | --- | --- | --- | --- | --- | --- |
| millions of dollars |  |  |  |  |  |  |  |
| Balance, December 31, 2021 | $7,242 | $1,422 | $79 | $25 | $1,348 | $34 | $10,150 |
| Net income of Emera Inc. | - | - | - | - | 1,008 | 1 | 1,009 |
| Other comprehensive income, net of tax expense of $1 million | - | - | - | 553 | - | - | 553 |
| Dividends declared on preferred stock (note 28) | - | - | - | - | (63) | - | (63) |
| Dividends declared on common stock ($2.6775/share) | - | - | - | - | (709) | - | (709) |
| Issued under the at-the-market program ('ATM'), net of after-tax issuance costs | 248 | - | - | - | - | - | 248 |
| Issued under the Dividend Reinvestment Program ('DRIP'), net of discount | 238 | - | - | - | - | - | 238 |
| Senior management stock options exercised and Employee Share Purchase Plan | 34 | - | 2 | - | - | - | 36 |
| Disposal of non-controlling interest of Dominica Electricity Services Ltd ('Domlec') | - | - | - | - | - | (20) | (20) |
| Other | - | - | - | - | - | (1) | (1) |
| Balance, December 31, 2022 | $7,762 | $1,422 | $81 | $578 | $1,584 | $14 | $11,441 |
| Balance, December 31, 2020 | $6,705 | $1,004 | $79 | $(79) | $1,495 | $34 | $9,238 |
| Net income of Emera Inc. | - | - | - | - | 560 | 1 | 561 |
| Other comprehensive income, net of tax expense of $14 million | - | - | - | 104 | - | - | 104 |
| Issuance of preferred stock, net of after-tax issuance costs | - | 418 | - | - | - | - | 418 |
| Dividends declared on preferred stock (note 28) | - | - | - | - | (50) | - | (50) |
| Dividends declared on common stock ($2.5750/share) | - | - | - | - | (657) | - | (657) |
| Issued under the ATM, net of after-tax issuance costs | 284 | - | - | - | - | - | 284 |
| Issued under the DRIP, net of discount | 215 | - | - | - | - | - | 215 |
| Senior management stock options exercised and Employee Share Purchase Plan | 38 | - | - | - | - | - | 38 |
| Other | - | - | - | - | - | (1) | (1) |
| Balance, December 31, 2021 | $7,242 | $1,422 | $79 | $25 | $1,348 | $34 | $10,150 |

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

10

# **Emera Incorporated**  
**Notes to the Consolidated Financial Statements**  
**As at December 31, 2022 and 2021**

# **1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES**

# **Nature of Operations**

Emera Incorporated ('Emera' or the 'Company') is an energy and services company which invests in electricity generation, transmission and distribution, and gas transmission and distribution.

At December 31, 2022, Emera's reportable segments include the following:

- • Florida Electric Utility, which consists of Tampa Electric, a vertically integrated regulated electric utility, serving approximately 827,000 customers in West Central Florida;
- • Canadian Electric Utilities, which includes:
  - • Nova Scotia Power Inc. ('NSPI'), a vertically integrated regulated electric utility and the primary electricity supplier in Nova Scotia, serving approximately 541,000 customers; and
  - • Emera Newfoundland & Labrador Holdings Inc. ('ENL'), consisting of two transmission investments related to an 824 megawatt ('MW') hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador, owned and constructed by Nalcor Energy. ENL's two investments are:
    - • a 100 per cent investment in NSP Maritime Link Inc. ('NSPML'), which developed the Maritime Link Project, a \$1.8 billion (including allowance for funds used during construction ('AFUDC')) transmission project; and
    - • a 31.9 per cent investment in the partnership capital of Labrador-Island Link Limited Partnership ('LIL'), a \$3.7 billion electricity transmission project in Newfoundland and Labrador.
- • Gas Utilities and Infrastructure, which includes:
  - • Peoples Gas System ('PGS'), a regulated gas distribution utility, serving approximately 468,000 customers across Florida;
  - • New Mexico Gas Company, Inc. ('NMGC'), a regulated gas distribution utility, serving approximately 545,000 customers in New Mexico;
  - • Emera Brunswick Pipeline Company Limited ('Brunswick Pipeline'), a 145-kilometre pipeline delivering re-gasified liquefied natural gas ('LNG') from Saint John, New Brunswick to the United States border under a 25-year firm service agreement with Repsol Energy North America Canada Partnership, which expires in 2034;
  - • SeaCoast Gas Transmission, LLC ('SeaCoast'), a regulated intrastate natural gas transmission company in Florida; and
  - • a 12.9 per cent interest in Maritimes & Northeast Pipeline ('M&NP'), a 1,400-kilometre pipeline that transports natural gas throughout markets in Atlantic Canada and the northeastern United States.
- • Other Electric Utilities, which includes Emera (Caribbean) Incorporated ('ECI'), a holding company with regulated electric utilities that include:
  - • The Barbados Light & Power Company Limited ('BLPC'), a vertically integrated regulated electric utility on the island of Barbados, serving approximately 133,000 customers;
  - • Grand Bahama Power Company Limited ('GBPC'), a vertically integrated regulated electric utility on Grand Bahama Island, serving approximately 19,000 customers; and
  - • a 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.

11

- • 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 30 MW biomass co-generation electricity facility in Brooklyn, Nova Scotia; and
    - • a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC ('Bear Swamp'), a 660 MW pumped storage hydroelectric facility in northwestern Massachusetts.
  - • Emera US Finance LP ('Emera Finance') and TECO Finance, Inc. ('TECO Finance'), financing subsidiaries of Emera;
  - • Emera Technologies LLC, a wholly owned technology company focused on finding ways to deliver renewables and resilient energy to customers;
  - • Emera US Holdings Inc., a wholly owned holding company for certain of Emera's assets located in the United States; and
  - • Other investments.

## Basis of Presentation

These consolidated financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles ('USGAAP') and in the opinion of management, include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera.

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

## Principles of Consolidation

These consolidated financial statements include the accounts of Emera Incorporated, its majority-owned subsidiaries, and a variable interest entity ('VIE') in which Emera is the primary beneficiary. Emera uses the equity method of accounting to record investments in which the Company has the ability to exercise significant influence, and for VIEs in which Emera is not the primary beneficiary.

The Company performs ongoing analysis to assess whether it holds any VIEs or whether any reconsideration events have arisen with respect to existing VIEs. To identify potential VIEs, management reviews contractual and ownership arrangements such as leases, long-term purchase power agreements, tolling contracts, guarantees, jointly owned facilities and equity investments. VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impacts its economic performance and the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where Emera has an investment in a VIE but is not deemed the primary beneficiary, the VIE is accounted for using the equity method. For further details on VIEs, refer to note 32.

Intercompany balances and transactions have been eliminated on consolidation, except for the net profit on certain transactions between certain non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non-regulated operating revenues. An offset is recorded to PP&E, regulatory assets, regulated fuel for generation and purchased power, or OM&G, depending on the nature of the transaction.

12

## Use of Management Estimates

The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations ('ARO'), and valuation of financial instruments. Management evaluates the Company's estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise.

## Regulatory Matters

Regulatory accounting applies where rates are established by, or subject to approval by, an independent third-party regulator. The rates are designed to recover prudently incurred costs of providing the regulated products or services and provide an opportunity for a reasonable rate of return on invested capital, as applicable. For further detail, refer to note 7.

## Foreign Currency Translation

Monetary assets and liabilities denominated in foreign currencies are converted to CAD at the rates of exchange prevailing at the balance sheet date. The resulting differences between the translation at the original transaction date and the balance sheet date are included in income.

Assets and liabilities of foreign operations whose functional currency is not the Canadian dollar are translated using exchange rates in effect at the balance sheet date and the results of operations at the average exchange rate in effect for the period. The resulting exchange gains and losses on the assets and liabilities are deferred on the balance sheet in AOCI.

The Company designates certain USD denominated debt held in CAD functional currency companies as hedges of net investments in USD denominated foreign operations. The change in the carrying amount of these investments, measured at the exchange rates in effect at the balance sheet date is recorded in Other Comprehensive Income ('OCI').

## Revenue Recognition

### *Regulated Electric and Gas Revenue:*

Electric and gas revenues, including energy charges, demand charges, basic facilities charges and clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is when electricity and gas are delivered to customers over time as the customer simultaneously receives and consumes the benefits. Electric and gas revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity and gas are recognized at rates approved by the respective regulator and recorded based on metered usage, which occurs on a periodic, systematic basis, generally monthly or bi-monthly. At the end of each reporting period, the electricity and gas delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. The Company's estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of megawatt hours ('MWh') or therms delivered to customers at the established rates expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of energy demand, weather, line losses and inter-period changes to customer classes.

13

#### *Non-regulated Revenue:*

Marketing and trading margins are comprised of Emera Energy's corresponding purchases and sales of natural gas and electricity, pipeline capacity costs and energy asset management revenues. Revenues are recorded when obligations under the terms of the contract are satisfied and are presented on a net basis, reflecting the nature of the contractual relationships with customers and suppliers.

Energy sales are recognized when obligations under the terms of the contracts are satisfied, which is when electricity is delivered to customers over time.

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

#### *Other:*

Sales, value add, and other taxes, except for gross receipts taxes discussed below, collected by the Company concurrent with revenue-producing activities are excluded from revenue.

#### **Leases**

The Company determines whether a contract contains a lease at inception by evaluating if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration.

Emera has leases with independent power producers ('IPP') and other utilities with annual requirements to purchase wind and hydro energy over varying contract lengths that are classified as finance leases. These finance leases are not recorded on the Company's Consolidated Balance Sheets, as payments associated with the leases are variable in nature and there are no minimum fixed lease payments. Lease expense associated with these leases is recorded as 'Regulated fuel for generation and purchased power' on the Consolidated Statements of Income.

Operating lease liabilities and right-of-use assets are recognized on the Consolidated Balance Sheets based on the present value of the future minimum lease payments over the lease term at commencement date. As most of Emera's leases do not provide an implicit rate, the incremental borrowing rate at commencement of the lease is used in determining the present value of future lease payments. Lease expense is recognized on a straight-line basis over the lease term and is recorded as 'Operating, maintenance and general' on the Consolidated Statements of Income.

Where the Company is the lessor, a lease is a sales-type lease if certain criteria are met and the arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria are met due to the presence of a third-party residual value guarantee, the lease is a direct financing lease.

For direct finance leases, a net investment in the lease is recorded that consists of the sum of the minimum lease payments and residual value, net of estimated executory costs and unearned income. The difference between the gross investment and the cost of the leased item is recorded as unearned income at the inception of the lease. Unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease.

For sales-type leases, the accounting is similar to the accounting for direct finance leases, however the difference between the fair value and the carrying value of the leased item is recorded at lease commencement rather than deferred over the term of the lease.

Emera has certain contractual agreements that include lease and non-lease components, which management has elected to account for as a single lease component.

14

## Franchise Fees and Gross Receipts

Tampa Electric and PGS recover from customers certain costs incurred, on a dollar-for-dollar basis, through prices approved by the Florida Public Service Commission ('FPSC'). The amounts included in customers' bills for franchise fees and gross receipt taxes are included as 'Regulated electric' and 'Regulated gas' revenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Statements of Income in 'Provincial, state and municipal taxes'.

NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC's franchise fees and gross receipt taxes are presented net with no line item impact on the Consolidated Statements of Income.

## Property, Plant and Equipment

PP&E are recorded at original cost, including AFUDC or capitalized interest, net of contributions received in aid of construction.

The cost of additions, including betterments and replacements of units are included in 'Property, plant and equipment'. When units of regulated PP&E are replaced, renewed or retired, their cost, plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no gain or loss reflected in income. Where a disposition of non-regulated PP&E occurs, gains and losses are included in income as the dispositions occur.

The cost of PP&E represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or interest for non-regulated property, ARO, and overhead attributable to the capital project. Overhead includes corporate costs such as finance, information technology and labour costs, along with other costs related to support functions, employee benefits, insurance, procurement, and fleet operating and maintenance. Expenditures for project development are capitalized if they are expected to have a future economic benefit.

Normal maintenance projects and major maintenance projects that do not increase the overall life of the related assets are expensed as incurred. When a major maintenance project increases the life or value of the underlying asset, the cost is capitalized.

Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each functional class of depreciable property. For some of Emera's rate-regulated subsidiaries, depreciation is calculated using the group remaining life method, which is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property. The service lives of regulated assets require regulatory approval.

Intangible assets, which are included in 'Property, plant and equipment,' consist primarily of computer software and land rights. Amortization is determined by the straight-line method, based on the estimated remaining service lives of the asset in each category. For some of Emera's rate-regulated subsidiaries, amortization is calculated using the amortizable life method which is applied to the net book value to date over the remaining life of those assets. The service lives of regulated intangible assets require regulatory approval.

15

## Goodwill

Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated fair values of identifiable assets acquired and liabilities assumed at the acquisition date. Goodwill is carried at initial cost less any write-down for impairment and is adjusted for the impact of foreign exchange. Under the applicable accounting guidance, goodwill is subject to assessment for impairment at the reporting unit level annually, or if an event or change in circumstances indicates that the fair value of a reporting unit may be below its carrying value. When assessing goodwill for impairment, the Company has the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. In performing a qualitative assessment management considers, among other factors, macroeconomic conditions, industry and market considerations and overall financial performance.

If the Company performs the qualitative assessment and determines that it is more likely than not that its fair value is less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a quantitative test is performed. The quantitative test compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, an impairment loss is recorded. Management estimates the fair value of the reporting unit by using the income approach, or a combination of the income and market approach. The income approach is applied using a discounted cash flow analysis which relies on management's best estimate of the reporting units' projected cash flows. The analysis includes an estimate of terminal values based on these expected cash flows using a methodology which derives a valuation using an assumed perpetual annuity based on the reporting unit's residual cash flows. The discount rate used is a market participant rate based on a peer group of publicly traded comparable companies and represents the weighted average cost of capital of comparable companies. When using the market approach, management estimates fair value based on comparable companies and transactions within the utility industry. Significant assumptions used in estimating the fair value include discount and growth rates, rate case assumptions including future cost of capital, valuation of the reporting units' net operating loss ('NOL') and projected operating and capital cash flows. Adverse changes in these assumptions could result in a future material impairment of the goodwill assigned to Emera's reporting units.

As of December 31, 2022, $6,009 million of Emera's goodwill represents the excess of the acquisition purchase price for TECO Energy (Tampa Electric, PGS and NMGC reporting units) over the fair values assigned to identifiable assets acquired and liabilities assumed. In Q4 2022, qualitative assessments were performed for Tampa Electric and PGS given the significant excess of fair value over carrying amounts calculated during the last quantitative test in Q4 2019. Management concluded it was more likely than not that the fair value of these reporting units exceeded their respective carrying amounts, including goodwill. As such, no quantitative testing was required. For the NMGC reporting unit, Emera elected to bypass a qualitative assessment and performed a quantitative impairment assessment using a combination of the income and market approach. This assessment estimated that the fair value of the NMGC reporting unit exceeded its carrying amount, including goodwill. As a result of this assessment, no impairment charges were recognized.

In Q4 2022, the Company elected to bypass a qualitative assessment and performed a quantitative impairment assessment for GBPC, using the income approach, as this reporting unit is sensitive to changes in assumptions due to limited excess of fair value over the carrying value, including goodwill. Although the cash flows of GBPC have not changed significantly compared to previous periods, it was determined that the carrying amount, including goodwill, exceeded the fair value, due to an increase in discount rates. The discount rate for the reporting unit was negatively impacted by changes in the macroeconomic environment, including the risk-free rate assumption. As a result of this assessment, a goodwill impairment charge of $73 million was recorded in 2022, reducing the GBPC goodwill balance to nil as at December 31, 2022. No impairment was recorded in 2021. For further detail, refer to note 22.

16

## Income Taxes and Investment Tax Credits

Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included in the financial statements or income tax returns. Deferred income tax assets and liabilities are determined based on the difference between the carrying value of assets and liabilities on the Consolidated Balance Sheets, and their respective tax bases using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in income tax rates on deferred income tax assets and liabilities is recognized in earnings in the period when the change is enacted, unless required to be offset to a regulatory asset or liability by law or by order of the regulator. Emera recognizes the effect of income tax positions only when it is more likely than not that they will be realized. Management reviews all readily available current and historical information, including forward-looking information, and the likelihood that deferred tax assets will be recovered from future taxable income is assessed and assumptions about the expected timing of the reversal of deferred tax assets and liabilities are made. If management subsequently determines that it is likely that some or all of a deferred income tax asset will not be realized, then a valuation allowance is recorded to reflect the amount of deferred income tax asset expected to be realized.

Generally, investment tax credits are recorded as a reduction to income tax expense in the current or future periods to the extent that realization of such benefit is more likely than not. Investment tax credits earned by Tampa Electric, PGS and NMGC on regulated assets are deferred and amortized over the estimated service lives of the related properties, as required by regulatory practices.

Tampa Electric, PGS, NMGC and BLPC collect income taxes from customers based on current and deferred income taxes. NSPI, ENL and Brunswick Pipeline collect income taxes from customers based on income tax that is currently payable except for the deferred income taxes on certain regulatory balances specifically prescribed by the regulator. For the balance of regulated deferred income taxes, NSPI, ENL and Brunswick Pipeline recognize regulatory assets or liabilities where the deferred income taxes are expected to be recovered from or returned to customers in future years. These regulated assets or liabilities are grossed up using the respective income tax rate to reflect the income tax associated with future revenues that are required to fund these deferred income tax liabilities, and the income tax benefits associated with reduced revenues resulting from the realization of deferred income tax assets. GBPC is not subject to income taxes.

Emera classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively. For further detail, refer to note 10.

## Derivatives and Hedging Activities

The Company manages its exposure to normal operating and market risks relating to commodity prices, foreign exchange, interest rates and share prices through contractual protections with counterparties where practicable, and by using financial instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. These physical and financial contracts are classified as held-for-trading ('HFT'). Collectively, these contracts and financial instruments are considered derivatives.

The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales ('NPNS') exception. Physical contracts that meet the NPNS exception are not recognized on the balance sheet; these contracts are recognized in income when they settle. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company's business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty creditworthy. The Company continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met.

17

Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the change in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value with any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.

Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates. Tampa Electric has no derivatives related to hedging as a result of a FPSC approved five-year moratorium on hedging of natural gas purchases which ends on December 31, 2022. Tampa Electric's moratorium on hedging of natural gas purchases will continue through December 31, 2024, as a result of Tampa Electric's 2021 rate case settlement agreement.

Derivatives that do not meet any of the above criteria are designated as HFT, with changes in fair value normally recorded in net income of the period. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply.

Emera classifies gains and losses on derivatives as a component of fuel for generation and purchased power, other expenses, inventory, OM&G and PP&E, depending on the nature of the item being economically hedged. Transportation capacity arising as a result of marketing and trading derivative transactions is recognized as an asset in 'Receivables and other current assets' and amortized over the period of the transportation contract term. Cash flows from derivative activities are presented in the same category as the item being hedged within operating or investing activities on the Consolidated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on the Consolidated Statements of Cash Flows.

Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the fair value amounts of cash collateral with the same counterparty. Rights to reclaim cash collateral are recognized in 'Receivables and other current assets' and obligations to return cash collateral are recognized in 'Accounts payable'.

### **Cash, Cash Equivalents and Restricted Cash**

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

### **Receivables and Allowance for Credit Losses**

Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be assessed on account balances after the due date. The Company recognizes allowances for credit losses to reduce accounts receivable for amounts expected to be uncollectable. Management estimates credit losses related to accounts receivable by considering historical loss experience, customer deposits, current events, the characteristics of existing accounts and reasonable and supportable forecasts that affect the collectability of the reported amount. Provisions for credit losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible.

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## **Inventory**

Fuel and materials inventories are valued at the lower of weighted-average cost or net realizable value, unless evidence indicates that the weighted-average cost will be recovered in future customer rates.

## **Asset Impairment**

### *Long-Lived Assets:*

Emera assesses whether there has been an impairment of long-lived assets and intangibles when a triggering event occurs, such as a significant market disruption or sale of a business.

The assessment involves comparing the undiscounted expected future cash flows to the carrying value of the asset. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset over its estimated fair value. The Company's assumptions relating to future results of operations or other recoverable amounts, are based on a combination of historical experience, fundamental economic analysis, observable market activity and independent market studies. The Company's expectations regarding uses and holding periods of assets are based on internal long-term budgets and projections, which consider external factors and market forces, as of the end of each reporting period. The assumptions made are consistent with generally accepted industry approaches and assumptions used for valuation and pricing activities.

As at December 31, 2022, there are no indications of impairment of Emera's long-lived assets. No impairment charges related to long-lived assets were recognized in 2022 or 2021.

### *Equity Method Investments:*

The carrying value of investments accounted for under the equity method are assessed for impairment by comparing the fair value of these investments to their carrying values, if a fair value assessment was completed, or by reviewing for the presence of impairment indicators. If an impairment exists, and it is determined to be other-than-temporary, a charge is recognized in earnings equal to the amount the carrying value exceeds the investment's fair value. No impairment of equity method investments was required in either 2022 or 2021.

### *Financial Assets:*

Equity investments, other than those accounted for under the equity method, are measured at fair value, with changes in fair value recognized in the Consolidated Statements of Income. Equity investments that do not have readily determinable fair values are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or similar investments. No impairment of financial assets was required in either 2022 or 2021.

## **Asset Retirement Obligations**

An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation may exist under an existing or enacted law or statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel.

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An ARO represents the fair value of the estimated cash flows necessary to discharge the future obligation, using the Company's credit adjusted risk-free rate. The amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports, prior experience, estimated useful lives, and governmental regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long-lived asset. Over time, the liability is accreted to its estimated future value. AROs are included in 'Other long-term liabilities' and accretion expense is included as part of 'Depreciation and amortization'. Any regulated accretion expense not yet approved by the regulator is recorded in 'Property, plant and equipment' and included in the next depreciation study.

Some of the Company's transmission and distribution assets may have conditional AROs which are not recognized in the consolidated financial statements, as the fair value of these obligations could not be reasonably estimated, given there is insufficient information to do so. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Management monitors these obligations and a liability is recognized at fair value in the period in which an amount can be determined.

### **Cost of Removal**

Tampa Electric, PGS, NMGC and NSPI recognize non-ARO costs of removal ('COR') as regulatory liabilities. The non-ARO COR represent funds received from customers through depreciation rates to cover estimated future non-legally required COR of PP&E upon retirement. The companies accrue for COR over the life of the related assets based on depreciation studies approved by their respective regulators. The costs are estimated based on historical experience and future expectations, including expected timing and estimated future cash outlays.

### **Stock-Based Compensation**

The Company has several stock-based compensation plans: a common share option plan for senior management; an employee common share purchase plan; a deferred share unit ('DSU') plan; a performance share unit ('PSU') plan; and a restricted share unit ('RSU') plan. The Company accounts for its plans in accordance with the fair value-based method of accounting for stock-based compensation. Stock-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee's or director's requisite service period using the graded vesting method. Stock-based compensation plans recognized as liabilities are initially measured at fair value and re-measured at fair value at each reporting date, with the change in liability recognized in income.

### **Employee Benefits**

The costs of the Company's pension and other post-retirement benefit programs for employees are expensed over the periods during which employees render service. The Company recognizes the funded status of its defined-benefit and other post-retirement plans on the balance sheet and recognizes changes in funded status in the year the change occurs. The Company recognizes the unamortized gains and losses and past service costs in AOCI or regulatory assets. The components of net periodic benefit cost other than the service cost component are included in 'Other income, net' on the Consolidated Statements of Income. For further detail, refer to note 21.

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## 2. CHANGE IN ACCOUNTING POLICY

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

### **Facilitation of the Effects of Reference Rate Reform on Financial Reporting**

The Company adopted Accounting Standard Update ('ASU') 2022-06, *Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848* in Q4 2022. The update extends the period of time preparers can utilize the reference rate reform relief guidance issued under ASU 2020-04, which was adopted by the Company in Q4 2020. The guidance in ASU 2022-06 was effective as of the date of issuance and entities may elect to apply the guidance prospectively through to December 31, 2024. The Company has applied the guidance permitted by ASU 2020-04 to certain debt agreements that were amended during the current period. The Company's transition from reference rates will not have a material impact on the consolidated financial statements.

## 3. FUTURE ACCOUNTING PRONOUNCEMENTS

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

## 4. DISPOSITIONS

On March 31, 2022, Emera completed the sale of its 51.9 per cent interest in Domlec for proceeds which approximated its carrying value. Domlec was included in the Company's Other Electric reportable segment up to its date of sale. The sale did not have a material impact on earnings.

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## 5. 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.

| millions of dollars | Florida Electric Utility | Canadian Electric Utilities | Gas Utilities and Infrastructure | Other Electric Utilities | Other | Inter-Segment Eliminations | Total |
| --- | --- | --- | --- | --- | --- | --- | --- |
| For the year ended December 31, 2022 |  |  |  |  |  |  |  |
| Operating revenues from external customers (1) | $3,280 | $1,675 | $1,697 | $518 | $418 | $ - | $7,588 |
| Inter-segment revenues (1) | 7 | - | 7 | - | 22 | (36) | - |
| Total operating revenues | 3,287 | 1,675 | 1,704 | 518 | 440 | (36) | 7,588 |
| Regulated fuel for generation and purchased power | 1,086 | 803 | - | 290 | - | (8) | 2,171 |
| Regulated cost of natural gas | - | - | 800 | - | - | - | 800 |
| OM&G | 625 | 338 | 365 | 123 | 156 | (11) | 1,596 |
| Provincial, state and municipal taxes | 235 | 43 | 83 | 3 | 3 | - | 367 |
| Depreciation and amortization | 507 | 259 | 118 | 61 | 7 | - | 952 |
| Income from equity investments | - | 87 | 21 | 4 | 17 | - | 129 |
| Other income (expense), net | 68 | 24 | 13 | - | 23 | 17 | 145 |
| Interest expense, net (2) | 185 | 136 | 81 | 19 | 288 | - | 709 |
| Impairment charge | - | - | - | 73 | - | - | 73 |
| Income tax expense (recovery) | 121 | (8) | 70 | - | 2 | - | 185 |
| Non-controlling interest in subsidiaries | - | - | - | 1 | - | - | 1 |
| Preferred stock dividends | - | - | - | - | 63 | - | 63 |
| Net income (loss) attributable to common shareholders | $596 | $215 | $221 | $(48) | $(39) | $ - | $945 |
| Capital expenditures | $1,425 | $507 | $574 | $63 | $6 | $ - | $2,575 |
| As at December 31, 2022 |  |  |  |  |  |  |  |
| Total assets | $21,053 | $8,223 | $7,737 | $1,337 | $2,835 | $(1,443) | $39,742 |
| Investments subject to significant influence | $ - | $1,241 | $128 | $49 | $ - | $ - | $1,418 |
| Goodwill | $4,739 | $ - | $1,270 | $ - | $3 | $ - | $6,012 |

(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E, OM&G, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments.

(2) Segment net income is reported on a basis that includes internally allocated financing costs of $13 million for the year ended December 31, 2022, between the Gas Utilities and Infrastructure and Other segments.

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| millions of dollars | Florida Electric Utility | Canadian Electric Utilities | Gas Utilities and Infrastructure | Other Electric Utilities | Other | Inter-Segment Eliminations | Total |
| --- | --- | --- | --- | --- | --- | --- | --- |
| For the year ended December 31, 2021 |  |  |  |  |  |  |  |
| Operating revenues from external customers (1) | $2,718 | $1,501 | $1,276 | $445 | $(175) | $ - | $5,765 |
| Inter-segment revenues (1) | 6 | - | 4 | - | 18 | (28) | - |
| Total operating revenues | 2,724 | 1,501 | 1,280 | 445 | (157) | (28) | 5,765 |
| Regulated fuel for generation and purchased power | 894 | 654 | - | 218 | - | (3) | 1,763 |
| Regulated cost of natural gas | - | - | 472 | - | - | - | 472 |
| OM&G | 536 | 291 | 325 | 140 | 106 | (30) | 1,368 |
| Provincial, state and municipal taxes | 212 | 43 | 69 | 4 | 2 | - | 330 |
| Depreciation and amortization | 469 | 246 | 121 | 58 | 8 | - | 902 |
| Income from equity investments | - | 103 | 20 | 4 | 16 | - | 143 |
| Other income (expenses), net | 59 | 12 | 11 | 15 | 1 | (5) | 93 |
| Interest expense, net (2) | 138 | 132 | 64 | 21 | 256 | - | 611 |
| Income tax expense (recovery) | 72 | 9 | 62 | 1 | (150) | - | (6) |
| Non-controlling interest in subsidiaries | - | - | - | 1 | - | - | 1 |
| Preferred stock dividends | - | - | - | - | 50 | - | 50 |
| Net income (loss) attributable to common shareholders | $462 | $241 | $198 | $21 | $(412) | $ - | $510 |
| Capital expenditures | $1,331 | $366 | $515 | $111 | $5 | $ - | $2,328 |
| As at December 31, 2021 |  |  |  |  |  |  |  |
| Total assets | $17,903 | $7,418 | $6,666 | $1,402 | $2,034 | $(1,179) | $34,244 |
| Investments subject to significant influence | $ - | $1,215 | $123 | $44 | $ - | $ - | $1,382 |
| Goodwill | $4,436 | $ - | $1,189 | $68 | $3 | $ - | $5,696 |

(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities. Management believes the elimination of these transactions would understate PP&E, OM&G, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments.

(2) Segment net income is reported on a basis that includes internally allocated financing costs of $13 million for the year ended December 31, 2021, between the Gas Utilities and Infrastructure and Other segments.

## Geographical Information

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

| For the millions of dollars | Year ended December 31 |  |
| --- | --- | --- |
|  | 2022 | 2021 |
| United States | $5,346 | $3,754 |
| Canada | 1,725 | 1,566 |
| Barbados | 384 | 292 |
| The Bahamas | 122 | 110 |
| Dominica | 11 | 43 |
|  | $7,588 | $5,765 |

Property Plant and Equipment:

| As at millions of dollars | December 31 2022 | December 31 2021 |
| --- | --- | --- |
| United States | $17,382 | $14,978 |
| Canada | 4,689 | 4,440 |
| Barbados | 583 | 535 |
| The Bahamas | 342 | 322 |
| Dominica | - | 78 |
|  | $22,996 | $20,353 |

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## 6. REVENUE

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

| millions of dollars | Electric |  |  | Gas | Other |  |  | Total |
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
|  | Florida Electric Utility | Canadian Electric Utilities | Other Electric Utilities | Gas Utilities and Infrastructure | Other | Inter-Segment Eliminations |  |  |
| For the year ended December 31, 2022 |  |  |  |  |  |  |  |  |
| Regulated Revenue |  |  |  |  |  |  |  |  |
| Residential | $1,799 | $834 | $184 | $800 | $ - | $ - | $ - | $3,617 |
| Commercial | 869 | 427 | 282 | 461 | - | - | - | 2,039 |
| Industrial | 230 | 353 | 32 | 83 | - | - | (7) | 691 |
| Other regulatory deferrals | 371 | 28 | 12 | - | - | - | - | 411 |
| Other (1) | 18 | 33 | 8 | 283 | - | - | (7) | 335 |
| Finance income (2)(3) | - | - | - | 61 | - | - | - | 61 |
| Regulated revenue | $3,287 | $1,675 | $518 | $1,688 | $ - | $(14) | $ - | $7,154 |
| Non-Regulated Revenue |  |  |  |  |  |  |  |  |
| Marketing and trading margin (4) | - | - | - | - | 143 | - | - | 143 |
| Other non-regulated operating revenue | - | - | - | 16 | 16 | (10) | - | 22 |
| Mark-to-market (3) | - | - | - | - | 281 | (12) | - | 269 |
| Non-regulated revenue | $ - | $ - | $ - | $16 | $440 | $(22) | $ - | $434 |
| Total operating revenues | $3,287 | $1,675 | $518 | $1,704 | $440 | $(36) | $ - | $7,588 |

For the year ended December 31, 2021

| Regulated Revenue |  |  |  |  |  |  |  |  |
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Residential | $1,449 | $797 | $165 | $642 | $ - | $ - | $ - | $3,053 |
| Commercial | 754 | 407 | 232 | 379 | - | - | - | 1,772 |
| Industrial | 215 | 237 | 26 | 65 | - | - | (2) | 541 |
| Other regulatory deferrals | 289 | 27 | 7 | - | - | - | - | 323 |
| Other (1) | 17 | 33 | 15 | 122 | - | - | (8) | 179 |
| Finance income (2)(3) | - | - | - | 58 | - | - | - | 58 |
| Regulated revenue | $2,724 | $1,501 | $445 | $1,266 | $ - | $(10) | $ - | $5,926 |
| Non-Regulated Revenue |  |  |  |  |  |  |  |  |
| Marketing and trading margin (4) | - | - | - | - | 102 | - | - | 102 |
| Other non-regulated operating revenue | - | - | - | 14 | 30 | (21) | - | 23 |
| Mark-to-market (3) | - | - | - | - | (289) | 3 | - | (286) |
| Non-regulated revenue | $ - | $ - | $ - | $14 | $(157) | $(18) | $(18) | $(161) |
| Total operating revenues | $2,724 | $1,501 | $445 | $1,280 | $(157) | $(28) | $ - | $5,765 |

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

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

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

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

### Remaining Performance Obligations

Remaining performance obligations primarily represent gas transportation contracts, lighting contracts and long-term steam supply arrangements with fixed contract terms. As of December 31, 2022, the aggregate amount of the transaction price allocated to remaining performance obligations was $450 million (2021 - $437 million). This amount includes $144 million of future performance obligations related to a gas transportation contract between SeaCoast and PGS through 2040. This amount excludes contracts with an original expected length of one year or less and variable amounts for which Emera recognizes revenue at the amount to which it has the right to invoice for services performed. Emera expects to recognize revenue for the remaining performance obligations through 2042.

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## 7. REGULATORY ASSETS AND LIABILITIES

Regulatory assets represent prudently incurred costs that have been deferred because it is probable they will be recovered through future rates or tolls collected from customers. Management believes existing regulatory assets are probable for recovery either because the Company received specific approval from the applicable regulator, or due to regulatory precedent established for similar circumstances. If management no longer considers it probable that an asset will be recovered, the deferred costs are charged to income.

Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for previous collections. If management no longer considers it probable that a liability will be settled, the related amount is recognized in income.

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

| As at millions of dollars | December 31 2022 | December 31 2021 |
| --- | --- | --- |
| Regulatory assets |  |  |
| Deferred income tax regulatory assets | $1,166 | $1,045 |
| Cost recovery clauses | 707 | 114 |
| Tampa Electric capital cost recovery for early retired assets | 674 | 657 |
| Pension and post-retirement medical plan | 369 | 291 |
| FAM | 307 | 145 |
| Storm reserve | 103 | - |
| NMGC winter event gas cost recovery | 69 | 117 |
| Storm restoration | 35 | 35 |
| Deferrals related to derivative instruments | 30 | 23 |
| Environmental remediations | 27 | 27 |
| Stranded cost recovery | 27 | 26 |
| Other | 106 | 86 |
|  | $3,620 | $2,566 |
| Current | $602 | $253 |
| Long-term | 3,018 | 2,313 |
| Total regulatory assets | $3,620 | $2,566 |
| Regulatory liabilities |  |  |
| Accumulated reserve - cost of removal | 895 | 819 |
| Deferred income tax regulatory liabilities | 877 | 863 |
| Deferrals related to derivative instruments | 230 | 241 |
| NMGC gas hedge settlements (note 18) | 162 | - |
| Cost recovery clauses | 70 | 35 |
| Self-insurance fund (note 32) | 30 | 28 |
| Storm reserve | - | 58 |
| Other | 9 | 11 |
|  | $2,273 | $2,055 |
| Current | $495 | $290 |
| Long-term | 1,778 | 1,765 |
| Total regulatory liabilities | $2,273 | $2,055 |

### Deferred Income Tax Regulatory Assets and Liabilities

To 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.

25

## **Cost Recovery Clauses**

These assets and liabilities are related to Tampa Electric, PGS and NMGC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC or New Mexico Public Regulation Commission ('NMPRC'), as applicable, on a dollar-for-dollar basis in a subsequent period.

## **Tampa Electric Capital Cost Recovery for Early Retired Assets**

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

## **Pension and Post-Retirement Medical Plan**

This asset is primarily related to the deferred costs of pension and post-retirement benefits at Tampa Electric, PGS and NMGC. It is included in rate base and earns a rate of return as permitted by the FPSC and NMPRC as applicable. It is amortized over the remaining service life of plan participants.

## **FAM**

This regulated asset is the difference between actual fuel costs and amounts recovered from NSPI customers through electricity rates in a given year and deferred to a FAM regulatory asset or liability and recovered from or returned to customers in subsequent periods. For the years 2020 through 2022, differences between actual fuel costs and fuel revenues recovered from customers will be recovered from customers in future periods. The Nova Scotia Utility and Review Board's ('UARB') decision to approve the fuel stability plan directed that any annual non-fuel revenues above NSPI's approved range of ROE are to be applied to the FAM.

## **Storm Reserve**

The storm reserve is for hurricanes and other named storms that cause significant damage to Tampa Electric and PGS systems. As allowed by the FPSC, if the charges to the storm reserve exceed the storm liability, the excess is to be carried as a regulatory asset. Tampa Electric and PGS can petition the FPSC to seek recovery of restoration costs over a 12-month period, or longer, as determined by the FPSC, as well as replenish the reserve. In September 2022, Tampa Electric and PGS were impacted by Hurricane Ian. For further information, refer to 'Storm Reserve - Hurricane Ian' in both Tampa Electric and PGS sections below.

## **NMGC Winter Event Gas Cost Recovery**

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

## **Storm Restoration**

This asset represents storm restoration costs incurred by GBPC. GBPC maintains insurance for its generation facilities and, as with most utilities, its transmission and distribution networks are not covered by commercial insurance.

26

In January 2020, the Grand Bahama Port Authority (“GBPA”) approved the recovery of $15 million USD of costs related to Hurricane Dorian in 2019, over a five-year period. The recovery was implemented through rates on January 1, 2021.

Restoration costs associated with Hurricane Matthew in 2016 are being recovered through an approved fuel charge. For further information, refer to “Storm Restoration Costs - Hurricane Matthew” in the GBPC section below.

#### **Deferrals Related to Derivative Instruments**

This asset is primarily related to NSPI deferring changes in fair value of derivatives that are documented as economic hedges or that do not qualify for NPNS exemption, as a regulatory asset or liability as approved by its regulator. The realized gain or loss is recognized when the hedged item settles in regulated fuel for generation and purchased power, inventory, other income, OM&G or PP&E, depending on the nature of the item being economically hedged.

#### **Environmental Remediations**

This asset is primarily related to PGS costs associated with environmental remediation at Manufactured Gas Plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is based on a settlement agreement approved by the FPSC.

#### **Stranded Cost Recovery**

Due to the decommissioning of a GBPC steam turbine in 2012, the GBPA approved the recovery of a $21 million USD stranded cost through electricity rates; it is included in rate base and is expected to be included in rates in future years.

#### **Accumulated Reserve - Cost of Removal (“COR”)**

This regulatory liability represents the non-ARO COR reserve in Tampa Electric, PGS, NMGC and NSPI. AROs represent the fair value of estimated cash flows associated with the Company’s legal obligation to retire its PP&E. Non-ARO COR represent estimated funds received from customers through depreciation rates to cover future COR of PP&E value upon retirement that are not legally required. This reduces rate base for ratemaking purposes. This liability is reduced as COR are incurred and increased as depreciation is recorded for existing assets and as new assets are put into service.

#### **NMGC Gas Hedge Settlements**

This regulatory liability represents the regulatory deferral of gas options exercised above strike price but will settle in cash in Q1 2023. The value from the cash settlement of this options will flow through to customers via the PGAC.

#### **Regulatory Environments and Updates**

##### **Florida Electric Utility**

Tampa Electric is regulated by the FPSC and is also subject to regulation by the Federal Energy Regulatory Commission (“FERC”). The FPSC sets rates at a level that allows utilities such as Tampa Electric to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC rate setting hearings which can occur at the initiative of Tampa Electric, the FPSC or other interested parties.

27

Tampa Electric's approved regulated return on equity ('ROE') range for 2022 and 2021 was 9.25 per cent to 11.25 per cent based on an allowed equity capital structure of 54 per cent. An ROE of 10.20 per cent (2021 - 10.25 per cent) is used for the calculation of the return on investments for clauses.

#### *Fuel Recovery and Other Cost Recovery Clauses:*

Tampa Electric has a fuel recovery clause approved by the FPSC, allowing the opportunity to recover fluctuating fuel expenses from customers through annual fuel rate adjustments. The FPSC annually approves cost-recovery rates for purchased power, capacity, environmental and conservation costs, including a return on capital invested. Differences between the prudently incurred fuel costs and the cost-recovery rates and amounts recovered from customers through electricity rates in a year are deferred to a regulatory asset or liability and recovered from or returned to customers in subsequent periods.

On January 23, 2023, Tampa Electric requested an adjustment to its fuel charges to recover the 2022 fuel under-recovery of $518 million USD over a period of 21 months. The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $170 million USD for the balance of 2023. The proposed changes will be decided by the FPSC in March 2023, and recovery is expected to begin in April 2023.

The mid-course fuel adjustment requested by Tampa Electric on January 19, 2022, was approved on March 1, 2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel and capacity costs of $169 million USD, and was spread over customer bills from April 1, 2022 through December 2022.

#### *Base Rates:*

On October 21, 2021, the FPSC approved a settlement agreement filed by Tampa Electric. The settlement agreement allows for an increase to rates of $191 million USD annually effective January 2022. This increase consisted of $123 million USD in base rate charges and $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 United States Treasury Bond yields exceed a specific threshold set on the date the FPSC approved the agreement. Under the agreement base rates are frozen from January 1, 2022 to December 31, 2024, unless Tampa Electric's earned ROE were to fall below the bottom of the range during that time. The settlement agreement provides for the deferral of income taxes as a result of changes in tax laws. The changes would be reflected as a regulatory asset or liability and either result in an increase or a decrease in customer rates through a subsequent regulatory process. The settlement agreement further creates a mechanism to recover the costs of retiring coal generation units and meter assets over a period of 15 years which survives the term of that agreement. The settlement agreement sets new depreciation and dismantlement rates effective January 1, 2022 and contains the provisions that Tampa Electric will not have to file another depreciation study during the term of the agreement but will file a new depreciation study no more than one year, nor less than 90 days, before the filing of its next general base rate proceeding. Tampa Electric agreed not to hedge natural gas through the period ending on December 31, 2024.

On August 16, 2022, the FPSC approved Tampa Electric's request to increase revenue and ROE due to increases in the 30-year United States Treasury bond yield rate. Effective July 1, 2022, the new mid-point ROE is 10.20 per cent, and the range is 9.25 per cent to 11.25 per cent.

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#### *Storm Reserve - Hurricane Ian:*

In September 2022, Tampa Electric was impacted by Hurricane Ian. Total restoration costs were $126 million USD, with $119 million USD of restoration costs charged against Tampa Electric's FPSC approved storm reserve. Total restoration costs charged to the storm reserve have exceeded the reserve balance and have been deferred as a regulatory asset for future recovery. On January 23, 2023, Tampa Electric petitioned the FPSC for recovery of the storm reserve regulatory asset and the replenishment of the balance in the reserve to the previous approved reserve level of $56 million USD, for a total of approximately $131 million USD. The proposed changes will be decided by the FPSC in March 2023 and recovery is expected to begin in April 2023 through March 2024.

#### *Solar Base Rate Adjustments Included in Base Rates:*

During 2017 to 2021, Tampa Electric invested $850 million USD in 600 MW of utility-scale solar photovoltaic projects, which is recoverable through FPSC-approved solar base rate adjustments ('SoBRAs'). AFUDC was earned on these projects during construction. The FPSC has approved SoBRAs representing a total of 600 MW or $104 million USD annually in estimated revenue requirements for in-service projects.

On October 12, 2021, the FPSC approved the true-up filing for SoBRA tranche 3, included in base rates as of January 2020. A $4 million USD true-up was returned to customers during 2021. No true-up for SoBRA tranche 4 was required.

#### *Storm Protection Cost Recovery Clause and Settlement Agreement:*

On October 3, 2019, the FPSC issued a rule to implement a Storm Protection Plan ('SPP') Cost Recovery Clause. This clause provides a process for Florida investor-owned utilities, including Tampa Electric, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. Differences between prudently incurred clause-recoverable costs and amounts recovered from customers through electricity rates in a year are deferred and recovered from or returned to customers in a subsequent year. A settlement agreement was approved on August 10, 2020, and Tampa Electric's cost recovery began in January 2021. The current approved plan addressed the years 2020 through 2022, and in April 2022 Tampa Electric submitted a new plan to determine cost recovery in 2023, 2024 and 2025. On October 4, 2022, the FPSC approved Tampa Electric's SPP.

#### *Big Bend Modernization Project:*

Tampa Electric invested $876 million USD, including $91 million USD of AFUDC, during 2018 through 2022 to modernize the Big Bend Power Station. The modernization project repowered Big Bend Unit 1 with natural gas combined-cycle technology and eliminated coal as this unit's fuel. As part of the modernization project, Tampa Electric retired the Unit 1 components that will not be used in the modernized plant in 2020 and Big Bend Unit 2 in 2021. Tampa Electric plans to retire Big Bend Unit 3 in 2023 as it is in the best interest of the customers from an economic, environmental risk and operational perspective.

At December 31, 2021, the balance sheet included $636 million USD in electric utility plant and $267 million USD in accumulated depreciation related to Unit 1 components and Unit 2 and Unit 3 assets. In accordance with Tampa Electric's 2017 settlement agreement approved by the FPSC, Tampa Electric continued to account for its existing investment in Unit 1, 2 and 3 in electric utility plant and depreciated the assets using the current depreciation rates until December 31, 2021, at which point they were reclassified to a regulatory asset on the balance sheet.

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Tampa Electric's 2021 settlement agreement provides recovery for the Big Bend Modernization project in two phases. The first phase was a revenue increase to cover the costs of the assets in service during 2022, among other items. The remainder of the project costs will be recovered as part of the 2023 subsequent year adjustment. The settlement agreement also includes a new charge to recover the remaining costs of the retiring Big Bend coal generation assets, Units 1 through 3, which will be spread over 15 years and will survive the termination of the settlement agreement. The special capital recovery schedule for all three units was applied beginning January 1, 2022. This recovery mechanism is authorized by and survives the term of the settlement agreement approved by the FPSC in 2021.

## Canadian Electric Utilities

### NSPI

NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia ("Public Utilities Act") and is subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI's operations and expenditures. Electricity rates for NSPI's customers are also subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings held from time to time at NSPI's or the UARB's request.

NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers and provide a reasonable return to investors. NSPI's approved regulated ROE range for 2022 and 2021 was 8.75 per cent to 9.25 per cent based on an actual five quarter average regulated common equity component of up to 40 per cent of approved rate base.

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

For the period of 2020 through 2022, NSPI operated under a three-year fuel stability plan which resulted in an average annual overall rate increase of 1.5 per cent to recover fuel costs. These rates included recovery of Maritime Link costs.

### General Rate Application ("GRA"):

On November 9, 2022, the Nova Scotia provincial government enacted Bill 212, "Public Utilities Act (amended)". The legislation limits non-fuel rate increases in NSPI's 2022 GRA to the UARB, excluding increases relating to demand side management ("DSM") costs, to a total of 1.8 per cent between the effective date of the UARB's decision and the end of 2024. The legislation also:

- requires revenue generated from the non-fuel rate increase to be used only to improve the reliability of service to ratepayers,
- limits NSPI's return on equity to 9.25 per cent and equity ratio to 40 per cent, and
- limits the rate used to accrue interest on regulatory deferrals to the Bank of Canada policy interest rate plus 1.75 per cent, unless otherwise directed by the UARB.

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On November 24, 2022, NSPI filed with the UARB a comprehensive settlement agreement between NSPI, key customer representatives and participating interest groups ('NSPI Settlement Agreement') in relation to its GRA filed in January 2022. The NSPI Settlement Agreement was structured to be consistent with the amendments to the Public Utilities Act made under Bill 212, including the 1.8 per cent cap on non-fuel rate increases for 2023 and 2024. The NSPI Settlement Agreement also addresses the recovery of fuel costs over the settlement period and establishes a DSM rider. This will result in a combined fuel and non-fuel rate increase of 6.9 per cent each year for 2023 and 2024, and annualised incremental revenue (fuel and non-fuel) of $105 million in 2023 and $115 million in 2024. In addition, any under or over recovery of fuel costs will be addressed through the UARB's established FAM process. NSPI's ROE range will continue to be 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 40 per cent. The NSPI Settlement Agreement also establishes a storm rider for each of 2023, 2024 and 2025, which gives NSPI the option to apply to the UARB for recovery of costs if major storm restoration expense exceeds approximately $10 million in a given year. On February 2, 2023, NSPI received the UARB's decision, which substantially approved the Settlement Agreement as filed. Approved rate increases will be effective as of the date of the decision.

#### *Maritime Link:*

The Maritime Link is a $1.8 billion (including AFUDC) transmission project including two 170-kilometre sub-sea cables, connecting the island of Newfoundland and Nova Scotia. The Maritime Link entered service on January 15, 2018 and NSPI started interim assessment payments to NSPML at that time. As part of a three-year fuel stability plan, electricity rates were set to include amounts of $164 million and $162 million for 2021 and 2022, respectively. Any difference between the amounts included in the fuel stability plan and those approved by the UARB through the NSPML interim assessment application will be addressed through the FAM.

#### *Nova Scotia Cap-and-Trade ('Cap-and-Trade') Program:*

As at December 31, 2022, the FAM includes a recovery of $172 million (December 31, 2021 - $38 million) non-cash accrual representing the estimated future cost of acquiring emissions credits for the 2019 through 2022 Cap-and-Trade compliance period. Emissions for the compliance period will not be finalized until the completion of the environmental audit which begins in March 2023. Emissions are currently based upon audited actual emissions from 2019 through 2021 and unaudited actuals for 2022. The total cost of compliance with the Cap-and-Trade program compliance period could change depending on the price paid for both credits at remaining provincial auctions and reserve credits purchased from the provincial government, and the results of the 2022 environmental emissions audit.

Lower than forecast Muskrat Falls energy received during the compliance period has resulted in the increased deployment of higher carbon-emitting generation sources. The Province of Nova Scotia has agreed to provide approximately $165 million of relief from the 2019 through 2022 compliance costs, which was equal to the total cost of compliance forecast at the time of the fuel update submitted by NSPI to the UARB in September 2022 as part of the GRA. Discussions related to the final amount of relief and how this relief will be provided are ongoing. Further, NSPI's regulatory framework provides for the recovery of costs prudently incurred to comply with the Cap-and-Trade Program Regulations pursuant to NSPI's FAM.

#### **NSPML**

Equity earnings from the Maritime Link are dependent on the approved ROE and operational performance of NSPML. NSPML's approved regulated ROE range is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 30 per cent.

Nalcor's Nova Scotia Block ('NS Block') delivery obligations commenced on August 15, 2021 and delivery will continue over the next 35 years pursuant to the agreements.

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In February 2022, the UARB issued its decision and Board Order approving NSPML's requested rate base of approximately $1.8 billion less $9 million of costs ($7 million after-tax) that would not have otherwise been recoverable if incurred by NSPI. NSPML also received approval to collect up to $168 million (2021 - $172 million) from NSPI for the recovery of costs associated with the Maritime Link in 2022. This was subject to a holdback of up to $2 million a month, beginning April 2022, contingent on receiving at least 90 per cent of NS Block deliveries, including Supplemental Energy deliveries.

In December 2022, NSPML received UARB approval to collect up to $164 million from NSPI for the recovery of costs associated with the Maritime Link in 2023. This continues to be subject to a holdback of up to $2 million a month, as discussed above. On December 22, 2022, the UARB clarified its earlier direction regarding the holdback and NSPI can now release the holdback to NSPML when 90 per cent of NS Block deliveries, including Supplemental Energy deliveries, is achieved. This enabled NSPI to pay NSPML approximately $4 million of the 2022 holdback. As of December 31, 2022, an additional $14 million in aggregate has been held-back by NSPI. Determination of the allocation of the $14 million between NSPML and NSPI will be subject to a regulatory process that is expected to commence in early 2023 to review the holdback mechanism.

## Gas Utilities and Infrastructure

### PGS

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

PGS's approved ROE range for 2022 and 2021 was 8.9 per cent to 11.0 per cent with a 9.9 per cent midpoint, based on an allowed equity capital structure of 54.7 per cent.

#### *Fuel Recovery:*

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

#### *Recovery of Energy Conservation and Pipeline Replacement Programs:*

The FPSC annually approves a conservation charge that is intended to permit PGS to recover prudently incurred expenditures in developing and implementing cost effective energy conservation programs which are required by Florida law and approved and monitored by the FPSC. PGS also has a Cast Iron/Bare Steel Pipe Replacement clause to recover the cost of accelerating the replacement of cast iron and bare steel distribution lines in the PGS system. In February 2017, the FPSC approved expansion of the Cast Iron/Bare Steel clause to allow recovery of accelerated replacement of certain obsolete plastic pipe. The majority of cast iron and bare steel pipe has been removed from its system, with replacement of obsolete plastic pipe continuing until 2028 under the rider.

#### *Storm Reserve - Hurricane Ian:*

In September 2022, Hurricane Ian impacted PGS's operations in Fort Myers and Sarasota. The restoration costs were approximately $2 million USD and $1 million was charged against PGS's FPSC-approved storm reserve.

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#### *Base Rates:*

On November 19, 2020, the FPSC approved a settlement agreement filed by PGS. The settlement agreement allows for an increase to base rates by $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. It provides PGS the ability to reverse a total of $34 million USD of accumulated depreciation through 2023. During 2022, PGS reversed $14 million USD of the $34 million USD accumulated depreciation. No amounts were reversed prior to 2022. In addition, the agreement sets new depreciation rates effective January 1, 2021. Under the agreement base rates are frozen from January 1, 2021 to December 31, 2023, unless its earned ROE were to fall below 8.9 per cent before that time with an allowed equity in the capital structure of 54.7 per cent from investor sources of capital. The settlement agreement provides for the deferral of income taxes as a result of changes in tax laws. The changes would be reflected as a regulatory asset or liability and either result in an increase or a decrease in customer rates through a subsequent regulatory process.

#### **NMGC**

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

NMGC's approved ROE for 2022 and 2021 was 9.375 per cent on an allowed equity capital structure of 52 per cent.

#### *Fuel Recovery:*

NMGC recovers gas supply costs through a PGAC. This clause recovers actual costs for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, transmission, distribution, and sale of natural gas to its customers. On a monthly basis, NMGC can adjust the charges based on the next month's expected cost of gas and any prior month under-recovery or over-recovery. The NMPRC requires that NMGC annually file a reconciliation of the PGAC period costs and recoveries. NMGC must file a PGAC Continuation Filing with the NMPRC every four years to establish that the continued use of the PGAC is reasonable and necessary. In December 2020, NMGC received approval of its PGAC Continuation Filing for the four-year period ending December 2024.

#### *Base Rates:*

On December 13, 2021, NMGC filed a rate case with the NMPRC for new rates to become effective January 2023. On May 20, 2022, NMGC filed an unopposed settlement agreement with the NMPRC for an increase of $19 million USD in annual base revenues. The rates reflect the recovery of increased operating costs and capital investments in pipelines and related infrastructure. The NMPRC approved the settlement agreement on November 30, 2022.

#### *Weather Normalization Mechanism:*

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

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#### *Integrity Management Programs ('IMP') Regulatory Asset:*

A portion of NMGC's annual spending on infrastructure is for IMP, or the replacement and update of legacy systems. These programs are driven both by NMGC integrity management plans and federal and state mandates. In December 2020, NMGC received approval through its rate case to defer costs through an IMP regulatory asset for certain of its IMP capital investments occurring between January 1, 2022 and December 31, 2023 and petitioned recovery of the regulatory asset in its rate case filed on December 13, 2021. On November 30, 2022, the NMPRC issued a Final Order that included approval of recovery of the IMP regulatory asset.

#### **Brunswick Pipeline**

Brunswick Pipeline is a 145-kilometre pipeline delivering natural gas from the Saint John LNG import terminal near Saint John, New Brunswick to markets in the northeastern United States. Brunswick Pipeline entered into a 25-year firm service agreement commencing in July 2009 with Repsol Energy North America Canada Partnership. The agreement provides for a predetermined toll increase in the fifth and fifteenth year of the contract. The pipeline is considered a Group II pipeline regulated by the Canada Energy Regulator ('CER'). The CER Gas Transportation Tariff is filed by Brunswick Pipeline in compliance with the requirements of the CER Act and sets forth the terms and conditions of the transportation rendered by Brunswick Pipeline.

#### **Other Electric Utilities**

##### **BLPC**

BLPC is regulated by the Fair Trading Commission ('FTC'), an independent regulator, under the Utilities Regulation (Procedural) Rules 2003. BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on capital invested. BLPC's approved regulated return on rate base was 10 per cent for 2022 and 2021.

##### *Licenses:*

The Government of Barbados has granted BLPC a franchise to generate, transmit and distribute electricity on the island until 2028. In 2019, the Government of Barbados passed legislation amending the number of licenses required for the supply of electricity from a single integrated license which currently exists to multiple licenses for Generation, Transmission and Distribution, Storage, Dispatch and Sales. In March 2021, BLPC reached commercial agreement with the Government of Barbados for each of the license types, subject to the passage of implementing legislation. The new licenses are expected to take effect in 2023 on completion of the legislative process. The Dispatch license will have a term of 5 years with the remaining licenses having terms ranging from 25-30 years. BLPC anticipates that any increased costs associated with the implementation of the new multi-licensed structure will be recoverable through BLPC's regulatory framework. BLPC is awaiting final enactment and will work towards implementation of the licenses once received.

##### *Fuel Recovery*

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

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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 allowed regulatory ROE of 12.50 per cent on an allowed equity capital structure of 65 per cent. On September 16, 2022, the FTC granted BLPC interim rate relief, allowing an increase in base rates of approximately $3 million USD for the remainder of 2022 and approximately $1 million USD per month for 2023. Interim rate relief is effective from September 16, 2022 until the implementation of final rates. The hearing concluded in October 2022. On February 15, 2023, the FTC issued a decision on the BLPC rate review application which included the following significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent, a directive to update the major components of rate base to September 16, 2022, and a directive to establish regulatory liabilities of approximately $70 million USD related to the self-insurance fund, accumulated depreciation, and taxes. The impacts to BLPC's rate base and final rates are not yet determinable. BLPC will seek to clarify aspects of the FTC decision in its compliance filing and is also considering filing a submission to the FTC for a review of the decision. BLPC expects a decision on final rates from the FTC in 2023.

#### *Fuel Hedging:*

On October 21, 2021, the FTC approved BLPC's application to implement a fuel hedging program which will be incorporated into the calculation of the fuel clause adjustment. On November 10, 2021, BLPC requested the FTC review the required 50/50 cost sharing arrangement between BLPC and customers in relation to the hedging administrative costs, or any gains and losses associated with the hedging program. A decision is expected from the FTC in 2023.

#### **GBPC**

GBPC is regulated by the GBPA. The GBPA has granted GBPC a licensed, regulated and exclusive franchise to produce, transmit and distribute electricity on the island until 2054. Rates are set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on rate base. GBPC's approved regulated return on rate base was 8.23 per cent for 2022 (2021 - 8.37 per cent).

#### *Fuel Recovery:*

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

Effective November 1, 2022, GBPC's fuel pass through charge was increased due to an increase in global oil prices impacting the unhedged fuel cost. In 2023, the fuel pass through charge will be adjusted monthly, in-line with actual fuel costs.

#### *Base Rates:*

There is a fuel pass-through mechanism and tariff review policy with new rates submitted every three years. On January 14, 2022, the GBPA issued its decision on GBPC's application for rate review that was filed with the GBPA on September 23, 2021. The decision, which became effective April 1, 2022, allows for an increase in revenues of $3.5 million USD. The new rates include a regulatory ROE of 12.84 per cent.

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# *Storm Restoration Costs - Hurricane Matthew:*

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

# **8. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME**

| millions of dollars | Carrying Value As at December 31 |  | Equity Income For the year ended December 31 |  | Percentage of Ownership |
| --- | --- | --- | --- | --- | --- |
|  | 2022 | 2021 | 2022 | 2021 | 2022 |
| LIL (1) | $740 | $682 | $58 | $54 | 31.9 |
| NSPML | 501 | 533 | 29 | 49 | 100.0 |
| M&NP (2) | 128 | 123 | 21 | 20 | 12.9 |
| Lucelec (2) | 49 | 44 | 4 | 4 | 19.5 |
| Bear Swamp (3) | - | - | 17 | 16 | 50.0 |
|  | $1,418 | $1,382 | $129 | $143 |  |

(1) Emera indirectly owns 100 per cent of the Class B units, which comprises 24.5 per cent of the total units issued. Percentage ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy 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 49 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 $95 million (2021 - $104 million) is recorded in Other long-term liabilities on the Consolidated Balance Sheets.

Equity investments include a $9 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 millions of dollars | 2022 | December 31 2021 |
| --- | --- | --- |
| Balance Sheets |  |  |
| Current assets | $17 | $25 |
| PP&E | 1,517 | 1,587 |
| Regulatory assets | 265 | 247 |
| Non-current assets | 29 | 31 |
| Total assets | $1,828 | $1,890 |
| Current liabilities | $48 | $50 |
| Long-term debt (1) | 1,149 | 1,189 |
| Non-current liabilities | 130 | 118 |
| Equity | 501 | 533 |
| Total liabilities and equity | $1,828 | $1,890 |

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

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## 9. OTHER INCOME, NET

| For the millions of dollars | Year ended December 31 |  |
| --- | --- | --- |
|  | 2022 | 2021 |
| TECO Guatemala Holdings award (1) | $63 | $ - |
| AFUDC | 52 | 61 |
| Other | 30 | 32 |
|  | $145 | $93 |

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

## 10. INCOME TAXES

The income tax provision, for the years ended December 31, differs from that computed using the enacted combined Canadian federal and provincial statutory income tax rate for the following reasons:

| millions of dollars | 2022 | 2021 |
| --- | --- | --- |
| Income before provision for income taxes | $1,194 | $555 |
| Statutory income tax rate | 29.0% | 29.0% |
| Income taxes, at statutory income tax rate | 346 | 161 |
| Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities | (70) | (62) |
| Foreign tax rate variance | (44) | (42) |
| Amortization of deferred income tax regulatory liabilities | (33) | (33) |
| GBPC impairment charge | 21 | - |
| Tax effect of equity earnings | (10) | (16) |
| Tax credits | (18) | (13) |
| Other | (7) | (1) |
| Income tax expense (recovery) | $185 | $(6) |
| Effective income tax rate | 15% | (1%) |

On August 16, 2022, the United States Inflation Reduction Act ('IRA') was signed into legislation. The IRA includes numerous tax incentives for clean energy, such as the extension and modification of existing investment and production tax credits for projects placed in service through 2024 and introduces new technology-neutral clean energy related tax credits beginning in 2025. During 2022, the Company recorded a $9 million regulatory liability in recognition of its obligation to pass the incremental tax benefits realized to customers.

The following table reflects the composition of taxes on income from continuing operations presented in the Consolidated Statements of Income for the years ended December 31:

| millions of dollars | 2022 | 2021 |
| --- | --- | --- |
| Current income taxes |  |  |
| Canada | $25 | $20 |
| United States | 8 | 11 |
| Deferred income taxes |  |  |
| Canada | 120 | (33) |
| United States | 252 | 118 |
| Other | - | 2 |
| Investment tax credits |  |  |
| United States | (7) | (11) |
| Operating loss carryforwards |  |  |
| Canada | (92) | (64) |
| United States | (121) | (49) |
| Income tax expense (recovery) | $185 | $(6) |

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The following table reflects the composition of income before provision for income taxes presented in the Consolidated Statements of Income for the years ended December 31:

| millions of dollars | 2022 | 2021 |
| --- | --- | --- |
| Canada | $173 | $244 |
| United States | 1,063 | 289 |
| Other | (42) | 22 |
| Income before provision for income taxes | $1,194 | $555 |

The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at December 31 consisted of the following:

| millions of dollars | 2022 | 2021 |
| --- | --- | --- |
| Deferred income tax assets: |  |  |
| Tax loss carryforwards | $1,207 | $873 |
| Tax credit carryforwards | 415 | 375 |
| Regulatory liabilities - cost of removal | 177 | 170 |
| Derivative instruments | 45 | 188 |
| Other | 428 | 434 |
| Total deferred income tax assets before valuation allowance | 2,272 | 2,040 |
| Valuation allowance | (312) | (256) |
| Total deferred income tax assets after valuation allowance | $1,960 | $1,784 |
| Deferred income tax (liabilities): |  |  |
| PP&E | $(2,981) | $(2,622) |
| Regulatory assets | (219) | (78) |
| Derivative instruments | (125) | (197) |
| Other | (594) | (460) |
| Total deferred income tax liabilities | $(3,919) | $(3,357) |
| Consolidated Balance Sheets presentation: |  |  |
| Long-term deferred income tax assets | $237 | $295 |
| Long-term deferred income tax liabilities | (2,196) | (1,868) |
| Net deferred income tax liabilities | $(1,959) | $(1,573) |

Considering all evidence regarding the utilization of the Company's deferred income tax assets, it has been determined that Emera is more likely than not to realize all recorded deferred income tax assets, except for certain loss carryforwards and unrealized capital losses on long-term debt and investments. A valuation allowance of $312 million has been recorded as at December 31, 2022 (2021 - $256 million) related to the loss carryforwards, long-term debt and investments.

The Company intends to indefinitely reinvest earnings from certain foreign operations. Accordingly, as at December 31, 2022, $3.8 billion (2021 - $2.9 billion) in cumulative temporary differences for which deferred taxes might otherwise be required, have not been recognized. It is impractical to estimate the amount of income and withholding tax that might be payable if a reversal of temporary differences occurred.

38

Emera's NOL, capital loss and tax credit carryforwards and their expiration periods as at December 31, 2022 consisted of the following:

| millions of dollars | Tax Carryforwards | Subject to Valuation Allowance | Net Tax Carryforwards | Expiration Period |
| --- | --- | --- | --- | --- |
| Canada |  |  |  |  |
| NOL | $2,372 | $(977) | $1,395 | 2026 - 2042 |
| Capital loss | 79 | (79) | - | Indefinite |
| United States |  |  |  |  |
| Federal NOL | $2,082 | $ - | $2,082 | 2032 - Indefinite |
| State NOL | 1,489 | - | 1,489 | 2032 - Indefinite |
| Tax credit | 415 | - | 415 | 2025 - 2042 |
| Other |  |  |  |  |
| NOL | $73 | $(33) | $40 | 2023 - 2029 |

The following table provides details of the change in unrecognized tax benefits for the years ended December 31 as follows:

| millions of dollars | 2022 | 2021 |
| --- | --- | --- |
| Balance, January 1 | $28 | $30 |
| Increases due to tax positions related to current year | 5 | 4 |
| Increases due to tax positions related to a prior year | 2 | 1 |
| Decreases due to tax positions related to a prior year | (2) | (1) |
| Decreases due to settlement with tax authorities | - | (6) |
| Balance, December 31 | $33 | $28 |

The total amount of unrecognized tax benefits as at December 31, 2022 was $33 million (2021 - $28 million), which would affect the effective tax rate if recognized. The total amount of accrued interest with respect to unrecognized tax benefits was $7 million (2021 - $6 million) with $1 million interest expense recognized in the Consolidated Statements of Income (2021 - nil). No penalties have been accrued. The balance of unrecognized tax benefits could change in the next 12 months as a result of resolving Canada Revenue Agency ('CRA') and Internal Revenue Service audits. A reasonable estimate of any change cannot be made at this time.

During 2022, the CRA issued notices of reassessment to NSPI for the 2013 through 2016 taxation years. NSPI and the CRA are currently in a dispute with respect to the timing of certain tax deductions for its 2006 through 2010 and 2013 through 2016 taxation years. The ultimate permissibility of the tax deductions is not in dispute; rather, it is the timing of those deductions. The cumulative net amount in dispute to date is $126 million (2021 - $62 million), including interest. NSPI has prepaid $55 million (2021 - $23 million) of the amount in dispute, as required by CRA.

On November 29, 2019, NSPI filed a Notice of Appeal with the Tax Court of Canada with respect to its dispute of the 2006 through 2010 taxation years. Should NSPI be successful in defending its position, all payments including applicable interest will be refunded. If NSPI is unsuccessful in defending any portion of its position, the resulting taxes and applicable interest will be deducted from amounts previously paid, with the difference, if any, either owed to, or refunded from, the CRA. The related tax deductions will be available in subsequent years.

Should NSPI be similarly reassessed by the CRA for years not currently in dispute, further payments will be required; however, the ultimate permissibility of these deductions would be similarly not in dispute.

NSPI and its advisors believe that NSPI has reported its tax position appropriately. NSPI continues to assess its options to resolving the dispute; however, the outcome of the Notice of Appeal process is not determinable at this time.

39

Emera files a Canadian federal income tax return, which includes its Nova Scotia provincial income tax. Emera's subsidiaries file Canadian, US, Barbados, and St. Lucia income tax returns. As at December 31, 2022, the Company's tax years still open to examination by taxing authorities include 2005 and subsequent years.

## 11. COMMON STOCK

**Authorized:** Unlimited number of non-par value common shares.

| Issued and outstanding: | 2022 |  | 2021 |  |
| --- | --- | --- | --- | --- |
|  | millions of shares | millions of dollars | millions of shares | millions of dollars |
| Balance, December 31, 2021 | 261.07 | $7,242 | 251.43 | $6,705 |
| Issuance of common stock under ATM program (1)(2) | 4.07 | 248 | 4.99 | 284 |
| Issued under the DRIP, net of discounts | 4.21 | 238 | 3.90 | 215 |
| Senior management stock options exercised and Employee Share Purchase Plan | 0.60 | 34 | 0.75 | 38 |
| Balance, December 31, 2022 | 269.95 | $7,762 | 261.07 | $7,242 |

(1) As at December 31, 2021, a total of 4,987,123 common shares were issued under Emera's ATM program at an average price of $57.63 per share for gross proceeds of $287 million ($284 million net of after-tax issuance costs).

(2) For the year ended December 31, 2022, 4,072,469 common shares were issued under Emera's ATM program at an average price of $61.31 per share for gross proceeds of $250 million ($248 million net of after-tax issuance costs).

On August 12, 2021, Emera renewed its ATM Program that allows the Company to issue up to $600 million of common shares from treasury to the public from time to time, at the Company's discretion, at the prevailing market price. The ATM Program was renewed pursuant to a prospectus supplement to the Company's short form base shelf prospectus dated August 5, 2021. The ATM program is expected to remain in effect until September 5, 2023. As at December 31, 2022, an aggregate gross sales limit of $207 million remains available for issuance under the ATM program.

As at December 31, 2022, the following common shares were reserved for issuance: 6 million (2021 - 6.2 million) under the senior management stock option plan, 2.7 million (2021 - 3.1 million) under the employee common share purchase plan and 10 million (2021 - 14.2 million) under the DRIP.

The issuance of common shares under the common share compensation arrangements does not allow the plans to exceed 10 per cent of Emera's outstanding common shares. As at December 31, 2022, Emera is in compliance with this requirement.

## 12. EARNINGS PER SHARE

Basic earnings per share is determined by dividing net income attributable to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income attributable to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive items include Company contributions to the senior management stock option plan, convertible debentures and shares issued under the DRIP.

40

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

| For the millions of dollars (except per share amounts) | Year ended December 31 |  |
| --- | --- | --- |
|  | 2022 | 2021 |
| Numerator |  |  |
| Net income attributable to common shareholders | $945.1 | $510.5 |
| Diluted numerator | 945.1 | 510.5 |
| Denominator |  |  |
| Weighted average shares of common stock outstanding | 265.5 | 255.9 |
| Weighted average deferred share units outstanding (1) | - | 1.3 |
| Weighted average shares of common stock outstanding - basic | 265.5 | 257.2 |
| Stock-based compensation | 0.4 | 0.4 |
| Weighted average shares of common stock outstanding - diluted | 265.9 | 257.6 |
| Earnings per common share |  |  |
| Basic | $3.56 | $1.98 |
| Diluted | $3.55 | $1.98 |

(1) Effective February 10, 2022, deferred share units are no longer able to be settled in shares and are therefore no longer included in the calculation of earnings per common share.

### 13. ACCUMULATED OTHER COMPREHENSIVE INCOME

The components of AOCI are as follows:

| millions of dollars | Unrealized gain (loss) on translation of self-sustaining foreign net investment operations | Net change in net investment hedges | Gains on derivatives recognized as cash flow hedges | Net change on available- for-sale investments | Net change in unrecognized pension and post-retirement benefit costs | Total AOCI |
| --- | --- | --- | --- | --- | --- | --- |
| For the year ended December 31, 2022 |  |  |  |  |  |  |
| Balance, January 1, 2022 | $10 | $35 | $18 | $(1) | $(37) | $25 |
| Other comprehensive income (loss) before reclassifications | 629 | (97) | - | (1) | - | 531 |
| Amounts reclassified from AOCI | - | - | (2) | - | 24 | 22 |
| Net current period other comprehensive income (loss) | 629 | (97) | (2) | (1) | 24 | 553 |
| Balance, December 31, 2022 | $639 | $(62) | $16 | $(2) | $(13) | $578 |
| For the year ended December 31, 2021 |  |  |  |  |  |  |
| Balance, January 1, 2021 | $52 | $30 | $1 | $(1) | $(161) | $(79) |
| Other comprehensive (loss) income before reclassifications | (42) | 5 | 18 | - | - | (19) |
| Amounts reclassified from AOCI | - | - | (1) | - | 124 | 123 |
| Net current period other comprehensive income (loss) | (42) | 5 | 17 | - | 124 | 104 |
| Balance, December 31, 2021 | $10 | $35 | $18 | $(1) | $(37) | $25 |

41

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

| For the millions of dollars | Year ended December 31 |  |
| --- | --- | --- |
|  | 2022 | 2021 |
| Affected line item in the Consolidated Financial Statements |  |  |
| Gains on derivatives recognized as cash flow hedges |  |  |
| Interest rate hedge | Interest expense, net $ | (2) $(1) |
| Net change in unrecognized pension and post-retirement benefit costs |  |  |
| Actuarial losses | Other income, net $ | 10 $24 |
| Amounts reclassified into obligations | Pension and post-retirement benefits | 15 102 |
| Total before tax |  | 25 126 |
| Income tax expense |  | (1) (2) |
| Total net of tax | $ | 24 $124 |
| Total reclassifications out of AOCI, net of tax, for the period | $ | 22 $123 |

## 14. INVENTORY

| As at millions of dollars | December 31 2022 | December 31 2021 |
| --- | --- | --- |
| Fuel | $404 | $255 |
| Materials | 365 | 283 |
| Total | $769 | $538 |

## 15. DERIVATIVE INSTRUMENTS

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

| As at millions of dollars | Derivative Assets |  | Derivative Liabilities |  |
| --- | --- | --- | --- | --- |
|  | December 31 2022 | December 31 2021 | December 31 2022 | December 31 2021 |
| Regulatory deferral: |  |  |  |  |
| Commodity swaps and forwards | $186 | $146 | $42 | $16 |
| FX forwards | 18 | 7 | 1 | 8 |
| Physical natural gas purchases and sales | 52 | 88 | - | - |
|  | 256 | 241 | 43 | 24 |
| HFT derivatives: |  |  |  |  |
| Power swaps and physical contracts | 89 | 33 | 77 | 32 |
| Natural gas swaps, futures, forwards, physical contracts | 340 | 208 | 1,224 | 818 |
|  | 429 | 241 | 1,301 | 850 |
| Other derivatives: |  |  |  |  |
| Equity derivatives | - | 11 | 5 | - |
| FX forwards | 5 | - | 23 | - |
|  | 5 | 11 | 28 | - |
| Total gross current derivatives | 690 | 493 | 1,372 | 874 |
| Impact of master netting agreements: |  |  |  |  |
| Regulatory deferral | (18) | (4) | (18) | (4) |
| HFT derivatives | (276) | (188) | (276) | (188) |
| Total impact of master netting agreements | (294) | (192) | (294) | (192) |
| Total derivatives | $396 | $301 | $1,078 | $682 |
| Current (1) | 296 | 195 | 888 | 533 |
| Long-term (1) | 100 | 106 | 190 | 149 |
| Total derivatives | $396 | $301 | $1,078 | $682 |

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

42

## Cash Flow Hedges

On May 26, 2021, the treasury lock was settled for a gain of $19 million that is being amortized through interest expense over 10 years as the underlying hedged item settles. As of December 31, 2022, the unrealized gain in AOCI was $16 million, net of tax (2021 - $18 million, net of tax). For the year ended December 31, 2022, unrealized gains of $2 million (2021 - $1 million) have been reclassified from AOCI into interest expense. The Company expects $2 million of unrealized gains currently in AOCI to be reclassified into net income within the next twelve months.

## Regulatory Deferral

The Company has recorded the following changes in realized and unrealized gains (losses) with respect to derivatives receiving regulatory deferral:

| millions of dollars | Physical natural gas purchases | Commodity swaps and forwards | FX forwards | Physical natural gas purchases | Commodity swaps and forwards | FX forwards |
| --- | --- | --- | --- | --- | --- | --- |
| For the year ended December 31 |  |  | 2022 |  |  | 2021 |
| Unrealized gain (loss) in regulatory assets | $ - | $(69) | $1 | $ - | $(7) | $9 |
| Unrealized gain (loss) in regulatory liabilities | 28 | 343 | 16 | 88 | 218 | (3) |
| Realized loss in regulatory assets | - | 48 | - | - | - | - |
| Realized gain in regulatory liabilities | - | (41) | - | - | (3) | - |
| Realized (gain) loss in inventory (1) | - | (121) | 1 | - | (8) | 5 |
| Realized (gain) loss in regulated fuel for generation and purchased power (2) | (64) | (146) | - | - | (39) | 5 |
| Total change in derivative instruments | $(36) | $14 | $18 | $88 | $161 | $16 |

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

(2) Realized (gains) losses on derivative instruments settled and consumed in the period and hedging relationships that have been terminated or the hedged transaction is no longer probable.

As at December 31, 2022, the Company had the following notional volumes designated for regulatory deferral that are expected to settle as outlined below:

| millions | 2023 | 2024-2026 |
| --- | --- | --- |
| Physical natural gas purchases: |  |  |
| Natural gas (Mmbtu) | 6 | - |
| Commodity swaps and forwards purchases: |  |  |
| Natural gas (Mmbtu) | 18 | 12 |
| Power (MWh) | 1 | 1 |
| FX swaps and forwards: |  |  |
| FX contracts (millions of USD) | $206 | $123 |
| Weighted average rate | 1.2832 | 1.3064 |
| % of USD requirements | 50% | 28% |

## HFT Derivatives

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

| For the millions of dollars | Year ended December 31 2022 | 2021 |
| --- | --- | --- |
| Power swaps and physical contracts in non-regulated operating revenues | $17 | $4 |
| Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues | 47 | (142) |
| Total gains (losses) in net income | $64 | $(138) |

43

As at December 31, 2022, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:

| millions | 2023 | 2024 | 2025 | 2026 | 2027 and thereafter |
| --- | --- | --- | --- | --- | --- |
| Natural gas purchases (Mmbtu) | 319 | 92 | 42 | 36 | 131 |
| Natural gas sales (Mmbtu) | 492 | 205 | 105 | 6 | 19 |
| Power purchases (MWh) | 2 | - | - | - | - |
| Power sales (MWh) | 2 | - | - | - | - |

### Other Derivatives

As at December 31, 2022, the Company had equity derivatives in place to manage the cash flow risk associated with forecasted future cash settlements of deferred compensation obligations and FX forwards in place to manage cash flow risk associated with forecasted USD cash inflows. The equity derivatives hedge the return on 2.8 million shares and extends until December 2023. The FX forwards have a combined notional amount of $448 million USD and expire throughout 2023, 2024, and 2025.

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

| For the millions of dollars | 2022 |  | Year ended December 31 2021 |  |
| --- | --- | --- | --- | --- |
|  | FX Forwards | Equity Derivatives | FX Forwards | Equity Derivatives |
| Unrealized gain (loss) in OM&G | $ - | $(5) | $ - | $11 |
| Unrealized loss in other income, net | (18) | - | (15) | - |
| Realized gain (loss) in OM&G | - | (17) | - | 15 |
| Realized gain (loss) in other income, net | (6) | - | 18 | - |
| Total gains (losses) in net income | $(24) | $(22) | $3 | $26 |

### Credit Risk

The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty's non-performance under an agreement. The Company manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral are requested on any high-risk accounts.

The Company assesses the potential for credit losses on a regular basis and, where appropriate, maintains provisions. With respect to counterparties, the Company has implemented procedures to monitor the creditworthiness and credit exposure of counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties' credit standing, including those that are experiencing financial problems, have significant swings in default probability rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the Company's current default probability. Net asset positions are adjusted based on the counterparty's current default probability. The Company assesses credit risk internally for counterparties that are not rated.

As at December 31, 2022, the maximum exposure the Company had to credit risk was $1.9 billion (2021 - $1.3 billion), which includes accounts receivable net of collateral/deposits and assets related to derivatives.

44

It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, FX and interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit to the Company for the value in excess of the credit limit where contractually required. The total cash deposits/collateral on hand as at December 31, 2022 was $386 million (2021 - $341 million), which mitigates the Company's maximum credit risk exposure. The Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer required by the Company.

The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk to these counterparties. The Company generally enters into International Swaps and Derivatives Association agreements, North American Energy Standards Board agreements and, or Edison Electric Institute agreements. The Company believes entering into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance and default.

As at December 31, 2022, the Company had $131 million (2021 - $114 million) in financial assets, considered to be past due, which have been outstanding for an average 60 days. The fair value of these financial assets is $114 million (2021 - $93 million), the difference of which is included in the allowance for credit losses. These assets primarily relate to accounts receivable from electric and gas revenue.

### Concentration Risk

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

| As at | December 31, 2022 |  | December 31, 2021 |  |
| --- | --- | --- | --- | --- |
|  | millions of dollars | % of total exposure | millions of dollars | % of total exposure |
| Receivables, net |  |  |  |  |
| Regulated utilities: |  |  |  |  |
| Residential | $455 | 19% | $384 | 24% |
| Commercial | 192 | 8% | 167 | 10% |
| Industrial | 121 | 5% | 54 | 3% |
| Other | 122 | 5% | 91 | 6% |
|  | 890 | 37% | 696 | 43% |
| Trading group: |  |  |  |  |
| Credit rating of A- or above | 125 | 5% | 66 | 4% |
| Credit rating of BBB- to BBB+ | 75 | 3% | 107 | 7% |
| Not rated | 307 | 13% | 132 | 8% |
|  | 507 | 21% | 305 | 19% |
| Other accounts receivable | 585 | 25% | 329 | 20% |
|  | 1,982 | 83% | 1,330 | 82% |
| Derivative Instruments (current and long-term) |  |  |  |  |
| Credit rating of A- or above | 202 | 9% | 155 | 9% |
| Credit rating of BBB- to BBB+ | 8 | 0% | 22 | 1% |
| Not rated | 186 | 8% | 124 | 8% |
|  | 396 | 17% | 301 | 18% |
|  | $2,378 | 100% | $1,631 | 100% |

45

## Cash Collateral

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

| As at millions of dollars | December 31 2022 | December 31 2021 |
| --- | --- | --- |
| Cash collateral provided to others | $224 | $212 |
| Cash collateral received from others | $112 | $100 |

Collateral is posted in the normal course of business based on the Company's creditworthiness, including its senior unsecured credit rating as determined by certain major credit rating agencies. Certain derivatives contain financial assurance provisions that require collateral to be posted if a material adverse credit-related event occurs. If a material adverse event resulted in the senior unsecured debt falling below investment grade, the counterparties to such derivatives could request ongoing full collateralization.

As at December 31, 2022, the total fair value of derivatives in a liability position was $1,078 million (December 31, 2021 - $682 million). If the credit ratings of the Company were reduced below investment grade, the full value of the net liability position could be required to be posted as collateral for these derivatives.

## 16. FAIR VALUE MEASUREMENTS

The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exemption (see note 1) and uses a market approach to do so. The three levels of the fair value hierarchy are defined as follows:

Level 1 - Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets ("quoted prices") for identical assets and liabilities.

Level 2 - Where quoted prices for identical assets and liabilities are not available, the valuation of certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing houses.

Level 3 - Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally-developed inputs. The primary reasons for a Level 3 classification are as follows:

- While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials.
- The term of certain transactions extends beyond the period when quoted prices are available and, accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term.
- The valuations of certain transactions were based on internal models, although quoted prices were utilized in the valuations.

Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

46

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

| As at millions of dollars | Level 1 | Level 2 | Level 3 | December 31, 2022 Total |
| --- | --- | --- | --- | --- |
| Assets |  |  |  |  |
| Regulatory deferral: |  |  |  |  |
| Commodity swaps and forwards | $120 | $48 | $ - | $168 |
| FX forwards | - | 18 | - | 18 |
| Physical natural gas purchases | - | - | 52 | 52 |
|  | 120 | 66 | 52 | 238 |
| HFT derivatives: |  |  |  |  |
| Power swaps and physical contracts | 9 | 31 | 4 | 44 |
| Natural gas swaps, futures, forwards, physical contracts and related transportation | 3 | 72 | 34 | 109 |
|  | 12 | 103 | 38 | 153 |
| Other derivatives: |  |  |  |  |
| FX forwards | - | 5 | - | 5 |
| Total assets | 132 | 174 | 90 | 396 |
| Liabilities |  |  |  |  |
| Regulatory deferral: |  |  |  |  |
| Commodity swaps and forwards | 15 | 9 | - | 24 |
| FX forwards | - | 1 | - | 1 |
|  | 15 | 10 | - | 25 |
| HFT derivatives: |  |  |  |  |
| Power swaps and physical contracts | 2 | 28 | 1 | 31 |
| Natural gas swaps, futures, forwards and physical contracts | 51 | 118 | 825 | 994 |
|  | 53 | 146 | 826 | 1,025 |
| Other derivatives: |  |  |  |  |
| FX forwards | - | 23 | - | 23 |
| Equity derivatives | 5 | - | - | 5 |
|  | 5 | 23 | - | 28 |
| Total liabilities | 73 | 179 | 826 | 1,078 |
| Net assets (liabilities) | $59 | $(5) | $(736) | $(682) |

47

| As at millions of dollars | Level 1 | Level 2 | Level 3 | Total |
| --- | --- | --- | --- | --- |
| Assets |  |  |  |  |
| Regulatory deferral: |  |  |  |  |
| Commodity swaps and forwards | $101 | $41 | $ - | $142 |
| FX forwards | - | 7 | - | 7 |
| Physical natural gas purchases and sales | - | - | 88 | 88 |
|  | 101 | 48 | 88 | 237 |
| HFT derivatives: |  |  |  |  |
| Power swaps and physical contracts | 4 | 5 | 4 | 13 |
| Natural gas swaps, futures, forwards, physical contracts and related transportation | (1) | 29 | 12 | 40 |
|  | 3 | 34 | 16 | 53 |
| Other derivatives: |  |  |  |  |
| Equity derivatives | 11 | - | - | 11 |
| Total assets | 115 | 82 | 104 | 301 |
| Liabilities |  |  |  |  |
| Regulatory deferral: |  |  |  |  |
| Commodity swaps and forwards | 7 | 5 | - | 12 |
| FX forwards | - | 8 | - | 8 |
|  | 7 | 13 | - | 20 |
| HFT derivatives: |  |  |  |  |
| Power swaps and physical contracts | 4 | 5 | 3 | 12 |
| Natural gas swaps, futures, forwards and physical contracts | 13 | 122 | 515 | 650 |
|  | 17 | 127 | 518 | 662 |
| Total liabilities | 24 | 140 | 518 | 682 |
| Net assets (liabilities) | $91 | $(58) | $(414) | $(381) |

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

| millions of dollars | Regulatory Deferral |  | HFT Derivatives |  | Total |
| --- | --- | --- | --- | --- | --- |
|  | Physical natural gas purchases |  | Power | Natural gas |  |
| Balance, January 1, 2022 | $88 |  | $4 | $12 | $104 |
| Realized gains included in fuel for generation and purchased power | (64) |  | - | - | (64) |
| Unrealized gains included in regulatory liabilities | 28 |  | - | - | 28 |
| Total realized and unrealized gains included in non-regulated operating revenues | - |  | - | 22 | 22 |
| Balance, December 31, 2022 | $52 |  | $4 | $34 | $90 |

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

| millions of dollars | HFT Derivatives |  | Total |
| --- | --- | --- | --- |
|  | Power | Natural gas |  |
| Balance, January 1, 2022 | $3 | $515 | $518 |
| Total realized and unrealized gains (losses) included in non-regulated operating revenues | (2) | 310 | 308 |
| Balance, December 31, 2022 | $1 | $825 | $826 |

48

Significant unobservable inputs used in the fair value measurement of Emera's natural gas and power derivatives include third-party sourced pricing for instruments based on illiquid markets. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair value measurement. Other unobservable inputs used include internally developed correlation factors and basis differentials; own credit risk; and discount rates. Internally developed correlations and basis differentials are reviewed on a quarterly basis based on statistical analysis of the spot markets in the various illiquid term markets. Discount rates may include a risk premium for those long-term forward contracts with illiquid future price points to incorporate the inherent uncertainty of these points. Any risk premiums for long-term contracts are evaluated by observing similar industry practices and in discussion with industry peers.

The Company uses a modelled pricing valuation technique for determining the fair value of Level 3 derivative instruments. The following table outlines quantitative information about the significant unobservable inputs used in the fair value measurements categorized within Level 3 of the fair value hierarchy:

| As at millions of dollars | Fair Value |  | Significant Unobservable Input | Low | December 31, 2022 |  |
| --- | --- | --- | --- | --- | --- | --- |
|  | Assets | Liabilities |  |  | High | Weighted average (1) |
| Regulatory deferral - Physical natural gas purchases | $52 | $ - | Third-party pricing | $5.79 | $31.85 | $12.27 |
| HFT derivatives - Power swaps and physical contracts | 4 | 1 | Third-party pricing | $43.24 | $269.10 | $138.79 |
| HFT derivatives - Natural gas swaps, futures, forwards and physical contracts | 34 | 825 | Third-party pricing | $2.45 | $33.88 | $12.01 |
| Total | $90 | $826 |  |  |  |  |
| Net liability |  | $736 |  |  |  |  |

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

| As at millions of dollars | Fair Value |  | Significant Unobservable Input | Low | December 31, 2021 |  |
| --- | --- | --- | --- | --- | --- | --- |
|  | Assets | Liabilities |  |  | High | Weighted average (1) |
| Regulatory deferral - Physical natural gas purchases | $88 | $ - | Third-party pricing | $4.51 | $26.09 | $9.74 |
| HFT derivatives - Power swaps and physical contracts | 4 | 3 | Third-party pricing | $37.05 | $213.00 | $99.34 |
| HFT derivatives - Natural gas swaps, futures, forwards and physical contracts | 12 | 515 | Third-party pricing | $1.90 | $21.53 | $8.80 |
| Total | $104 | $518 |  |  |  |  |
| Net liability |  | $414 |  |  |  |  |

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

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

| As at millions of dollars | Carrying Amount | Fair Value | Level 1 | Level 2 | Level 3 | Total |
| --- | --- | --- | --- | --- | --- | --- |
| December 31, 2022 | $16,318 | $14,670 | $ - | $14,284 | $386 | $14,670 |
| December 31, 2021 | $14,658 | $16,775 | $ - | $16,308 | $467 | $16,775 |

49

The Company has designated $1.2 billion USD denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in USD denominated operations. The Company's Hybrid Notes are contingently convertible into preferred shares in the event of bankruptcy or other related events. A redemption option on or after June 15, 2026 is available and at the control of the Company. The Hybrid Notes are classified as Level 2 financial assets. As at December 31, 2022, the fair value of the Hybrid Notes was $1.1 billion (2021 - $1.7 billion). An after-tax foreign currency loss of $97 million was recorded in AOCI for the year ended December 31, 2022 (2021 - $5 million after-tax gain).

## 17. RELATED PARTY TRANSACTIONS

In the ordinary course of business, Emera provides energy and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Intercompany balances and intercompany transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. All material amounts are under normal interest and credit terms.

Significant transactions between Emera and its associated companies are as follows:

- Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Consolidated Statements of Income. NSPI's expense is reported in Regulated fuel for generation and purchased power, totalling $157 million for the year ended December 31, 2022 (2021 - $149 million). NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments.
- Natural gas transportation capacity purchases from M&NP are reported in the Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $9 million for the year ended December 31, 2022 (2021 - $19 million).

There were no significant receivables or payables between Emera and its associated companies reported on Emera's Consolidated Balance Sheets as at December 31, 2022 and at December 31, 2021.

## 18. RECEIVABLES AND OTHER CURRENT ASSETS

| As at millions of dollars | December 31 2022 | December 31 2021 |
| --- | --- | --- |
| Customer accounts receivable - billed | $1,096 | $767 |
| Customer accounts receivable - unbilled | 424 | 318 |
| Allowance for credit losses | (17) | (21) |
| Capitalized transportation capacity (1) | 781 | 316 |
| NMGC gas hedge settlement receivable (2) | 162 | - |
| Income tax receivable | 9 | 8 |
| Prepaid expenses | 82 | 65 |
| Other | 360 | 280 |
| Total receivables and other current assets | $2,897 | $1,733 |

(1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract.

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

50

## 19. LEASES

### Lessee

The Company has operating leases for buildings, land, telecommunication services, and rail cars. Emera's leases have remaining lease terms of 1 year to 63 years, some of which include options to extend the leases for up to 65 years. These options are included as part of the lease term when it is considered reasonably certain that they will be exercised.

| As at millions of dollars | Classification | December 31 2022 | December 31 2021 |
| --- | --- | --- | --- |
| Right-of-use asset | Other long-term assets | $58 | $58 |
| Lease liabilities |  |  |  |
| Current | Other current liabilities | 3 | 3 |
| Long-term | Other long-term liabilities | 59 | 58 |
| Total lease liabilities |  | $62 | $61 |

The Company has recorded lease expense of $138 million for the year ended December 31, 2022 (2021 - $150 million), of which $131 million (2021 - $142 million) relates to variable costs for power generation facility finance leases, recorded in 'Regulated fuel for generation and purchased power' in the Consolidated Statements of Income.

Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter are as follows:

| millions of dollars | 2023 | 2024 | 2025 | 2026 | 2027 | Thereafter | Total |
| --- | --- | --- | --- | --- | --- | --- | --- |
| Minimum lease payments | $6 | $6 | $5 | $3 | $3 | $116 | $139 |
| Less imputed interest |  |  |  |  |  |  | (77) |
| Total |  |  |  |  |  |  | $62 |

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

| For the | Year ended December 31 2022 | December 31 2021 |
| --- | --- | --- |
| Cash paid for amounts included in the measurement of lease liabilities: |  |  |
| Operating cash flows for operating leases (millions of dollars) | $8 | $7 |
| Right-of-use assets obtained in exchange for lease obligations: |  |  |
| Operating leases (millions of dollars) | $1 | $ - |
| Weighted average remaining lease term (years) | 44 | 44 |
| Weighted average discount rate- operating leases | 3.98% | 3.98% |

### Lessor

The Company's net investment in direct finance and sales-type leases primarily relates to Brunswick Pipeline, Seacoast, compressed natural gas ('CNG') stations and heat pumps.

The Company manages its risk associated with the residual value of the Brunswick Pipeline lease through proper routine maintenance of the asset.

Customers have the option to purchase CNG station assets by paying a make-whole payment at the date of the purchase based on a targeted internal rate of return or may take possession of the CNG station asset at the end of the lease term for no cost. Customers have the option to purchase heat pumps at the end of the lease term for a nominal fee.

51

Commencing in January 2022, the Company leased a Seacoast pipeline, a 21-mile, 30-inch lateral that is classified as a sales-type lease. The term of the pipeline lateral lease is 34 years with a net investment of $100 million USD. The lessee of the new pipeline lateral has renewal options for an additional 16 years. These renewal options have not been included as part of the pipeline lateral lease term as it is not reasonably certain that they will be exercised.

Direct finance and sales-type lease unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease and is recorded as “Operating revenues - regulated gas” and “Other income, net” on the Consolidated Statements of Income.

The total net investment in direct finance and sales-type leases consist of the following:

| As at millions of dollars | December 31 2022 | December 31 2021 |
| --- | --- | --- |
| Total minimum lease payment to be received | $1,393 | $947 |
| Less: amounts representing estimated executory costs | (205) | (165) |
| Minimum lease payments receivable | $1,188 | $782 |
| Estimated residual value of leased property (unguaranteed) | 183 | 183 |
| Less: unearned finance lease income | (733) | (443) |
| Net investment in direct finance and sales-type leases | $638 | $522 |
| Principal due within one year (included in “Receivables and other current assets”) | 34 | 19 |
| Net Investment in direct finance and sales type leases - long-term | $604 | $503 |

As at December 31, 2022, future minimum lease payments to be received for each of the next five years and in aggregate thereafter are as follows:

| millions of dollars | 2023 | 2024 | 2025 | 2026 | 2027 | Thereafter | Total |
| --- | --- | --- | --- | --- | --- | --- | --- |
| Minimum lease payments to be received | $90 | $92 | $95 | $94 | $92 | $930 | $1,393 |
| Less: executory costs |  |  |  |  |  |  | (205) |
| Total |  |  |  |  |  |  | $1,188 |

## 20. PROPERTY, PLANT AND EQUIPMENT

PP&E consisted of the following regulated and non-regulated assets:

| As at millions of dollars | Estimated useful life | December 31 2022 | December 31 2021 |
| --- | --- | --- | --- |
| Generation | 2 to 131 | $13,083 | $11,173 |
| Transmission | 10 to 80 | 2,731 | 2,532 |
| Distribution | 10 to 65 | 6,978 | 6,305 |
| Gas transmission and distribution | 13 to 83 | 5,061 | 4,385 |
| General plant and other (1) | 2 to 71 | 2,723 | 2,473 |
| Total cost |  | 30,576 | 26,868 |
| Less: Accumulated depreciation (1) |  | (9,574) | (8,739) |
|  |  | 21,002 | 18,129 |
| Construction work in progress (1) |  | 1,994 | 2,224 |
| Net book value |  | $22,996 | $20,353 |

(1) SeaCoast owns a 50% undivided ownership interest in a jointly owned 26-mile pipeline lateral located in Florida, which went into service in 2020. At December 31, 2022, SeaCoast’s share of plant in service was $27 million USD (2021 - $27 million USD), and accumulated depreciation of $1 million USD (2021 - $1 million USD). SeaCoast’s undivided ownership interest is financed with its funds and all operations are accounted for as if such participating interest were a wholly owned facility. SeaCoast’s share of direct expenses of the jointly owned pipeline is included in OM&G in the Consolidated Statements of Income.

52

## 21. EMPLOYEE BENEFIT PLANS

Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, New Mexico, Barbados, and Grand Bahama Island.

Emera's net periodic benefit cost included the following:

### Benefit Obligation and Plan Assets

The changes in benefit obligation and plan assets, and the funded status for all plans were as follows:

| For the millions of dollars | 2022 |  | Year ended December 31 2021 |  |
| --- | --- | --- | --- | --- |
| Change in Projected Benefit Obligation ("PBO") and Accumulated Post- retirement Benefit Obligation ("APBO") | Defined benefit pension plans | Non-pension benefit plans | Defined benefit pension plans | Non-pension benefit plans |
| Balance, January 1 | $2,624 | $318 | $2,759 | $339 |
| Service cost | 41 | 4 | 43 | 5 |
| Plan participant contributions | 6 | 6 | 6 | 4 |
| Interest cost | 80 | 9 | 67 | 8 |
| Benefits paid | (174) | (31) | (160) | (27) |
| Actuarial gains | (480) | (79) | (89) | (10) |
| Settlements and curtailments | (6) | - | - | - |
| Foreign currency translation adjustment | 67 | 16 | (2) | (1) |
| Balance, December 31 | $2,158 | $243 | $2,624 | $318 |
| Change in plan assets |  |  |  |  |
| Balance, January 1 | $2,702 | $51 | $2,605 | $52 |
| Employer contributions | 45 | 24 | 42 | 21 |
| Plan participant contributions | 6 | 6 | 6 | 4 |
| Benefits paid | (174) | (31) | (160) | (27) |
| Actual return on assets, net of expenses | (489) | (7) | 214 | 2 |
| Settlements and curtailments | (6) | - | - | - |
| Foreign currency translation adjustment | 79 | 3 | (5) | (1) |
| Balance, December 31 | $2,163 | $46 | $2,702 | $51 |
| Funded status, end of year | $5 | $(197) | $78 | $(267) |

The actuarial gains recognized in the period are primarily due to changes in the discount rate and compensation-related assumption changes. This was partially offset by losses associated with member experience and indexation.

### Plans with PBO/APBO in Excess of Plan Assets

The aggregate financial position for all pension plans where the PBO or APBO (for post-retirement benefit plans) exceeds the plan assets for the years ended December 31 is as follows:

| millions of dollars | 2022 |  | 2021 |  |
| --- | --- | --- | --- | --- |
|  | Defined benefit pension plans | Non-pension benefit plans | Defined benefit pension plans | Non-pension benefit plans |
| PBO/APBO | $1,006 | $221 | $140 | $290 |
| Fair value of plan assets | 914 | - | 35 | - |
| Funded status | $(92) | $(221) | $(105) | $(290) |

### Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets

The ABO for the defined benefit pension plans was $2,080 million as at December 31, 2022 (2021 - $2,507 million). The aggregate financial position for those plans with an ABO in excess of the plan assets for the years ended December 31 is as follows:

53

| millions of dollars | 2022 | 2021 |
| --- | --- | --- |
|  | Defined benefit pension plans | Defined benefit pension plans |
| ABO | $111 | $133 |
| Fair value of plan assets | 33 | 35 |
| Funded status | $(78) | $(98) |

### Balance Sheet

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

| As at millions of dollars | December 31 2022 |  | December 31 2021 |  |
| --- | --- | --- | --- | --- |
|  | Defined benefit pension plans | Non-pension benefit plans | Defined benefit pension plans | Non-pension benefit plans |
| Other current liabilities | $(13) | $(20) | $(7) | $(20) |
| Long-term liabilities | (80) | (201) | (100) | (270) |
| Other long-term assets | 98 | 24 | 185 | 23 |
| AOCI, net of tax and regulatory assets | 358 | 22 | 230 | 90 |
| Less: Deferred income tax (expense) recovery in AOCI | (7) | (1) | (8) | 1 |
| Net amount recognized | $356 | $(176) | $300 | $(176) |

### Amounts Recognized in AOCI and Regulatory Assets

Unamortized gains and losses and past service costs arising on post-retirement benefits are recorded in AOCI or regulatory assets. The following table summarizes the change in AOCI and regulatory assets:

| millions of dollars | Regulatory assets | Actuarial (gains) losses |
| --- | --- | --- |
| Defined Benefit Pension Plans |  |  |
| Balance, January 1, 2022 | $192 | $30 |
| Amortized in current period | (21) | (10) |
| Current year addition to AOCI or regulatory assets | 147 | (5) |
| Change in FX rate | 18 | - |
| Balance, December 31, 2022 | $336 | $15 |
| Non-pension benefits plans |  |  |
| Balance, January 1, 2022 | $91 | $ - |
| Amortized in current period | (2) | - |
| Current year addition to AOCI or regulatory assets | (62) | (10) |
| Change in FX rate | 4 | - |
| Balance, December 31, 2022 | $31 | $(10) |

| As at millions of dollars | December 2022 |  | December 2021 |  |
| --- | --- | --- | --- | --- |
|  | Defined benefit pension plans | Non-pension benefit plans | Defined benefit pension plans | Non-pension benefit plans |
| Actuarial losses (gains) | $15 | $(10) | $30 | $ - |
| Deferred income tax expense (recovery) | 7 | 1 | 8 | (1) |
| AOCI, net of tax | 22 | (9) | 38 | (1) |
| Regulatory assets | 336 | 31 | 192 | 91 |
| AOCI, net of tax and regulatory assets | $358 | $22 | $230 | $90 |

### Benefit Cost Components

Emera's net periodic benefit cost included the following:

54

| As at millions of dollars | 2022 |  | Year ended December 31 2021 |  |
| --- | --- | --- | --- | --- |
|  | Defined benefit pension plans | Non-pension benefit plans | Defined benefit pension plans | Non-pension benefit plans |
| Service cost | $41 | $4 | $43 | $5 |
| Interest cost | 80 | 9 | 67 | 8 |
| Expected return on plan assets | (144) | - | (132) | (1) |
| Current year amortization of: |  |  |  |  |
| Actuarial losses | 8 | - | 21 | 3 |
| Regulatory assets (liability) | 21 | 2 | 24 | 2 |
| Settlement, curtailments | 2 | - | - | - |
| Total | $8 | $15 | $23 | $17 |

The expected return on plan assets is determined based on the market-related value of plan assets of $2,482 million as at January 1, 2022 (2021 - $2,151 million), adjusted for interest on certain cash flows during the year. The market-related value of assets is based on a five-year smoothed asset value. Any investment gains (or losses) in excess of (or less than) the expected return on plan assets are recognized on a straight-line basis into the market-related value of assets over a five-year period.

#### Pension Plan Asset Allocations

Emera's investment policy includes discussion regarding the investment philosophy, the level of risk which the Company is prepared to accept with respect to the investment of the Pension Funds, and the basis for measuring the performance of the assets. Central to the policy is the target asset allocation by major asset categories. The objective of the target asset allocation is to diversify risk and to achieve asset returns that meet or exceed the plan's actuarial assumptions. The diversification of assets reduces the inherent risk in financial markets by requiring that assets be spread out amongst various asset classes. Within each asset class, a further diversification is undertaken through the investment in a broad range of investment and non-investment grade securities. Emera's target asset allocation is as follows:

#### Canadian Pension Plans

| Asset Class | Target Range at Market |  |
| --- | --- | --- |
| Short-term securities | 0% | to 5% |
| Fixed income | 35% | to 50% |
| Equities: |  |  |
| Canadian | 7% | to 17% |
| Non-Canadian | 36% | to 60% |

#### Non-Canadian Pension Plans

| Asset Class | Target Range at Market Weighted average |  |
| --- | --- | --- |
| Fixed income | 30% | to 50% |
| Equities | 50% | to 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:

55

| millions of dollars | NAV | Level 1 | Level 2 | Total | Percentage |
| --- | --- | --- | --- | --- | --- |
| As at |  |  |  |  | December 31, 2022 |
| Cash and cash equivalents | $ - | $70 | $ - | $70 | 3% |
| Net in-transits | - | (70) | - | (70) | (3)% |
| Equity securities: |  |  |  |  |  |
| Canadian equity | - | 87 | - | 87 | 4% |
| United States equity | - | 233 | - | 233 | 11% |
| Other equity | - | 186 | - | 186 | 8% |
| Fixed income securities: |  |  |  |  |  |
| Government | - | - | 104 | 104 | 5% |
| Corporate | - | - | 83 | 83 | 4% |
| Other | - | 3 | 11 | 14 | 1% |
| Mutual funds | - | 68 | - | 68 | 3% |
| Other | - | - | (3) | (3) | - % |
| Open-ended investments measured at NAV (1) | 790 | - | - | 790 | 36% |
| Common collective trusts measured at NAV (2) | 601 | - | - | 601 | 28% |
| Total | $1,391 | $577 | $195 | $2,163 | 100% |

| As at |  |  |  |  | December 31, 2021 |
| --- | --- | --- | --- | --- | --- |
| Cash and cash equivalents | $ - | $60 | $ - | $60 | 2% |
| Net in-transits | - | (84) | - | (84) | (3)% |
| Equity securities: |  |  |  |  |  |
| Canadian equity | - | 97 | - | 97 | 4% |
| United States equity | - | 366 | - | 366 | 14% |
| Other equity | - | 215 | - | 215 | 8% |
| Fixed income securities: |  |  |  |  |  |
| Government | - | - | 132 | 132 | 5% |
| Corporate | - | - | 117 | 117 | 4% |
| Other | - | 8 | 3 | 11 | - % |
| Mutual funds | - | 86 | - | 86 | 3% |
| Other | - | 1 | (1) | - | - % |
| Open-ended investments measured at NAV (1) | 952 | - | - | 952 | 35% |
| Common collective trusts measured at NAV (2) | 750 | - | - | 750 | 28% |
| Total | $1,702 | $749 | $251 | $2,702 | 100% |

(1) NAV investments are open-ended registered and non-registered mutual funds, collective investment trusts, or pooled funds. NAV's are calculated at least monthly and the funds honor subscription and redemption activity regularly.

(2) The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying securities. Since the prices are not published to external sources, NAV is used as a practical expedient. Certain funds invest primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The funds honor subscription and redemption activity regularly.

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

#### Post-Retirement Benefit Plans

There are no assets set aside to pay for most of the Company's post-retirement benefit plans. As is common practice, post-retirement health benefits are paid from general accounts as required. The primary exceptions to this is the NMGC Retiree Medical Plan, which is fully funded.

#### Investments in Emera

As at December 31, 2022 and 2021, the assets related to the pension funds and post-retirement benefit plans did not hold any material investments in Emera or its subsidiaries securities. However, as a significant portion of assets for the benefit plan are held in pooled assets, there may be indirect investments in these securities.

56

## Cash Flows

The following table shows the expected cash flows for defined benefit pension and other post-retirement benefit plans:

| millions of dollars | Defined benefit pension plans | Non-pension benefit plans |
| --- | --- | --- |
| Expected employer contributions |  |  |
| 2023 | $44 | $20 |
| Expected benefit payments |  |  |
| 2023 | 164 | 22 |
| 2024 | 161 | 23 |
| 2025 | 168 | 23 |
| 2026 | 172 | 22 |
| 2027 | 178 | 22 |
| 2028 - 2032 | 919 | 105 |

## Assumptions

The following table shows the assumptions that have been used in accounting for defined benefit pension and other post-retirement benefit plans:

| (weighted average assumptions) | 2022 |  | 2021 |  |
| --- | --- | --- | --- | --- |
|  | Defined benefit pension plans | Non-pension benefit plans | Defined benefit pension plans | Non-pension benefit plans |
| Benefit obligation - December 31: |  |  |  |  |
| Discount rate - past service | 5.33% | 5.31% | 3.05% | 2.81% |
| Discount rate - future service | 5.34% | 5.32% | 3.18% | 2.92% |
| Rate of compensation increase | 3.62% | 3.61% | 3.31% | 3.29% |
| Health care trend - initial (next year) | - | 5.40% | - | 5.09% |
| - ultimate | - | 3.77% | - | 3.77% |
| - year ultimate reached | - | 2043 | - | 2042 |
| Benefit cost for year ended December 31: |  |  |  |  |
| Discount rate - past service | 3.05% | 2.81% | 2.49% | 2.48% |
| Discount rate - future service | 3.18% | 2.92% | 2.64% | 2.51% |
| Expected long-term return on plan assets | 6.07% | 1.32% | 5.86% | - % |
| Rate of compensation increase | 3.31% | 3.29% | 2.89% | 3.04% |
| Health care trend - initial (current year) | - | 5.09% | - | 5.64% |
| - ultimate | - | 3.77% | - | 4.35% |
| - year ultimate reached | - | 2042 | - | 2038 |

Actual assumptions used differ by plan.

The expected long-term rate of return on plan assets is based on historical and projected real rates of return for the plan's current asset allocation, and assumed inflation. A real rate of return is determined for each asset class. Based on the asset allocation, an overall expected real rate of return for all assets is determined. The asset return assumption is equal to the overall real rate of return assumption added to the inflation assumption, adjusted for assumed expenses to be paid from the plan.

The discount rate is based on high-quality long-term corporate bonds, with maturities matching the estimated cash flows from the pension plan.

## Defined Contribution Plan

Emera also provides a defined contribution pension plan for certain employees. The Company's contribution for the year ended December 31, 2022 was $41 million (2021 - $45 million).

57

## 22. GOODWILL

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

| millions of dollars | 2022 | 2021 |
| --- | --- | --- |
| Balance, January 1 | $5,696 | $5,720 |
| GBPC impairment charge (1) | (73) | - |
| Change in FX rate | 389 | (24) |
| Balance, December 31 | $6,012 | $5,696 |

(1) At the beginning of the period, Emera's accumulated impairment charges related to GBPC were $30 million.

Goodwill is subject to an annual assessment for impairment at the reporting unit level. The goodwill on Emera's Consolidated Balance Sheets at December 31, 2022, primarily relates to TECO Energy. Emera's reporting units with goodwill are Tampa Electric, PGS, NMGC, and GBPC.

In 2022, Emera performed a qualitative impairment assessment for Tampa Electric and PGS, concluding that the fair value of the reporting units exceeded their respective carrying amounts, and as such, no quantitative assessments were performed and no impairment charges were recognized. For the NMGC reporting unit, Emera elected to bypass a qualitative assessment and performed a quantitative impairment assessment using a combination of the income approach and market approach. This assessment estimated that the fair value of the NMGC reporting unit exceeded its carrying amount, including goodwill. As a result of this assessment, no impairment charges were recognized.

In 2022, the Company elected to bypass a qualitative assessment and performed a quantitative impairment assessment for GBPC, using the income approach, as this reporting unit is sensitive to changes in assumptions due to limited excess of fair value over carrying amount, including goodwill. Although the cash flows of GBPC have not changed significantly compared to previous periods, it was determined that the fair value did not exceed its carrying amount, including goodwill, primarily due to an increase in discount rates. The discount rate for the reporting unit was negatively impacted by changes in the macro-economic environment, including the risk-free rate assumption. As a result of this assessment, a goodwill impairment charge of $73 million was recorded in 2022, reducing the GBPC goodwill balance to nil as at December 31, 2022. This non-cash charge is included in 'Impairment charge' on the Consolidated Statements of Income.

58

## 23. SHORT-TERM DEBT

Emera's short-term borrowings consist of commercial paper issuances, advances on revolving and non-revolving credit facilities and short-term notes. Short-term debt and the related weighted-average interest rates as at December 31 consisted of the following:

| millions of dollars | 2022 | Weighted average interest rate | 2021 | Weighted average interest rate |
| --- | --- | --- | --- | --- |
| Tampa Electric Company ('TEC') |  |  |  |  |
| Advances on term, revolving and accounts receivable facilities | $1,380 | 5.00% | $945 | 0.58% |
| Emera |  |  |  |  |
| Non-revolving term facilities | 796 | 5.19% | 400 | 0.96% |
| Bank indebtedness | - | - % | 6 | - % |
| TECO Finance |  |  |  |  |
| Advances on revolving credit and term facilities | 481 | 5.47% | 355 | 1.20% |
| NMGC |  |  |  |  |
| Advances on revolving credit facilities | 59 | 5.15% | 25 | 1.20% |
| GBPC |  |  |  |  |
| Advances on revolving credit facilities | 10 | 5.25% | 10 | 5.25% |
| NSPI |  |  |  |  |
| Bank indebtedness | - | - % | 1 | - % |
| Short-term debt | $2,726 |  | $1,742 |  |

The Company's total short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows:

| millions of dollars | Maturity | 2022 | 2021 |
| --- | --- | --- | --- |
| TEC - Unsecured committed revolving credit facility | 2026 | $1,084 | $1,014 |
| TECO Energy/TECO Finance - revolving credit facility | 2026 | 542 | 507 |
| Emera - non-revolving term facility | 2023 | 400 | 400 |
| Emera - non-revolving term facility | 2023 | 400 | - |
| TEC - Unsecured non-revolving facility | 2023 | 542 | 634 |
| NMGC - revolving credit facility | 2026 | 169 | 158 |
| GBPC - revolving credit facility | on demand | 18 | 16 |
| Total |  | $3,155 | $2,729 |
| Less: |  |  |  |
| Advances under revolving credit and term facilities |  | 2,731 | 1,735 |
| Letters of credit issued within the credit facilities |  | 4 | 4 |
| Total advances under available facilities |  | 2,735 | 1,739 |
| Available capacity under existing agreements |  | $420 | $990 |

The weighted average interest rate on outstanding short-term debt at December 31, 2022 was 5.01 per cent (2021 - 0.83 per cent).

### Recent Significant Financing Activity by Segment

#### Florida Electric Utilities

On December 13, 2022, TEC amended its 364-day non-revolving term credit facility to extend the maturity date from December 16, 2022 to December 13, 2023 and reduced the facility amount from $500 million USD to $400 million USD. There were no other significant changes in commercial terms from the prior agreement.

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## Other

On December 16, 2022, Emera amended its $400 million non-revolving term credit facility to extend the maturity from December 16, 2022 to December 16, 2023. There were no other significant changes in commercial terms from the prior agreement.

On August 2, 2022, Emera entered into a $400 million non-revolving term facility which matures on August 2, 2023. The credit agreement contains customary representation and warranties, events of default and financial and other covenants and bears interest at Bankers' Acceptances or prime rate advances, plus a margin.

## 24. OTHER CURRENT LIABILITIES

| As at millions of dollars | December 31 2022 | December 31 2021 |
| --- | --- | --- |
| Accrued charges | $174 | $157 |
| Nova Scotia Cap-and-Trade Program provision (note 7) | 172 | - |
| Accrued interest on long-term debt | 97 | 75 |
| Pension and post-retirement liabilities (note 21) | 33 | 27 |
| Sales and other taxes payable | 14 | 6 |
| Income tax payable | 9 | 6 |
| Other | 80 | 95 |
|  | $579 | $366 |

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## 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:

| millions of dollars | Weighted average interest rate (1) |  | Maturity | 2022 | 2021 |
| --- | --- | --- | --- | --- | --- |
|  | 2022 | 2021 |  |  |  |
| Emera |  |  |  |  |  |
| Bankers acceptances, LIBOR loans | Variable | Variable | 2027 | $403 | $378 |
| Unsecured fixed rate notes | 2.90% | 2.90% | 2023 | 500 | 500 |
| Fixed to floating subordinated notes (USD) (2) | 6.75% | 6.75% | 2076 | 1,625 | 1,521 |
|  |  |  |  | $2,528 | $2,399 |
| Emera Finance |  |  |  |  |  |
| Unsecured senior notes (USD) | 3.65% | 3.65% | 2024 - 2046 | $3,725 | $3,487 |
| Tampa Electric (3) |  |  |  |  |  |
| Fixed rate notes and bonds (USD) | 4.15% | 4.15% | 2024 - 2052 | $4,341 | $3,683 |
| PGS |  |  |  |  |  |
| Fixed rate notes and bonds (USD) | 3.78% | 3.78% | 2024 - 2052 | $772 | $660 |
| NMGC |  |  |  |  |  |
| Fixed rate notes and bonds (USD) | 3.11% | 3.11% | 2026 - 2051 | $521 | $488 |
| Non-revolving term facility, floating rate | Variable | Variable | 2024 | 108 | 101 |
|  |  |  |  | $629 | $589 |
| NMGI |  |  |  |  |  |
| Fixed rate notes and bonds (USD) | 3.64% | 3.64% | 2024 | $203 | $190 |
| NSPI |  |  |  |  |  |
| Discount notes | Variable | Variable | 2024 - 2027 | $881 | $376 |
| Medium term fixed rate notes | 5.14% | 5.14% | 2025 - 2097 | 2,665 | 2,665 |
|  |  |  |  | $3,546 | $3,041 |
| EBP |  |  |  |  |  |
| Senior secured credit facility | Variable | Variable | 2026 | $249 | $249 |
| ECI |  |  |  |  |  |
| Secured senior notes (USD) | Variable | Variable | 2026 | $86 | $84 |
| Amortizing fixed rate notes (USD) | 3.97% | 3.97% | 2024 - 2026 | 100 | 104 |
| Non-revolving term facility, floating rate | Variable | Variable | 2027 | 30 | 28 |
| Non-revolving term facility, fixed rate | 2.05% | 2.36% | 2025 - 2026 | 91 | 101 |
| Secured fixed rate senior notes (4) | 3.06% | 4.43% | 2023 - 2029 | 142 | 161 |
|  |  |  |  | $449 | $478 |
| Adjustments |  |  |  |  |  |
| Fair market value adjustment - TECO Energy acquisition (5) |  |  |  | $2 | $3 |
| Debt issuance costs |  |  |  | (126) | (121) |
| Amount due within one year |  |  |  | (574) | (462) |
|  |  |  |  | $(698) | $(580) |
| Long-Term Debt |  |  |  | $15,744 | $14,196 |

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

(2) In 2022, the Company recognized $110 million in interest expense (2021 - $102 million) related to its fixed to floating subordinated notes.

(3) A substantial part of Tampa Electric's tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric's first mortgage bond indenture.

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

(5) On acquisition of TECO Energy, Emera recorded a fair market value adjustment on the unregulated long-term debt acquired. The fair market value adjustment is amortized over the remaining term of the debt.

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The Company's total long-term revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows:

| millions of dollars | Maturity | 2022 | 2021 |
| --- | --- | --- | --- |
| Emera - revolving credit facility (1) | June 2027 | $900 | $900 |
| NSPI - revolving credit facility (1) | December 2027 | 800 | 600 |
| NSPI - non-revolving credit facility | July 2024 | 400 | - |
| NMGC - non-revolving credit facility | March 2024 | 108 | - |
| ECI - revolving credit facilities | 2023-2032 | 11 | 27 |
| Total |  | $2,219 | $1,527 |
| Less: |  |  |  |
| Borrowings under credit facilities |  | 1,396 | 770 |
| Letters of credit issued inside credit facilities |  | 12 | 124 |
| Use of available facilities |  | $1,408 | $894 |
| Available capacity under existing agreements |  | $811 | $633 |

(1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $50 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:

|  | Financial Covenant | Requirement | As at December 31, 2022 |
| --- | --- | --- | --- |
| Emera |  |  |  |
| Syndicated credit facilities | Debt to capital ratio | Less than or equal to 0.70 to 1 | 0.57 : 1 |

## Recent Significant Financing Activity by Segment

### Florida Electric Utilities

On September 15, 2022, TEC repaid a $250 million USD note upon maturity. The note was repaid using existing credit facilities.

On July 12, 2022, TEC completed an issuance of $600 million USD senior notes. The issuance included $300 million USD senior notes that bear an interest rate of 3.875 per cent with a maturity date of July 12, 2024, and $300 million USD senior notes that bear an interest rate of 5 per cent with a maturity date of July 15, 2052.

### Canadian Electric Utilities

On December 16, 2022, NSPI amended its revolving operating credit facility to extend the maturity date from December 16, 2026 to December 16, 2027 and increase the amount of the facility from $600 million to $800 million. There were no other significant changes in commercial terms from the prior agreement.

On July 15, 2022, NSPI entered into a $400 million non-revolving term credit facility which matures on July 15, 2024. The credit facility contains customary representation and warranties, events of default and financial and other covenants, and bears interest at Bankers' Acceptances or prime rate advances, plus a margin.

### Gas Utilities and Infrastructure

On September 23, 2022, NMGC amended its $80 million USD, unsecured, non-revolving term credit facility to extend the maturity from September 23, 2022, to March 22, 2024. There were no other changes in commercial terms from the prior agreement.

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On June 30, 2022, Brunswick Pipeline amended its non-revolving credit agreement to extend the maturity from June 30, 2025 to June 30, 2026. There were no other changes in commercial terms from the prior agreement.

#### Other Electric Utilities

On March 25, 2022, ECI amended its amortizing floating rate notes to extend the maturity from March 25, 2022 to March 25, 2027. There were no other changes in commercial terms from the prior agreement.

#### Other

On December 16, 2022, Emera amended its $900 million revolving operating credit facility to extend the maturity date from June 30, 2026 to June 30, 2027. There were no other significant changes in commercial terms from the prior agreement.

#### Long-Term Debt Maturities

As at December 31, long-term debt maturities, including capital lease obligations, for each of the next five years and in aggregate thereafter are as follows:

| millions of dollars | 2023 | 2024 | 2025 | 2026 | 2027 | Thereafter | Total |
| --- | --- | --- | --- | --- | --- | --- | --- |
| Emera | $500 | $ - | $ - | $1,625 | $403 | $ - | $2,528 |
| Emera US Finance LP | - | 407 | - | 1,016 | - | 2,302 | 3,725 |
| Tampa Electric | - | 356 | - | - | - | 3,985 | 4,341 |
| PGS | - | 51 | - | - | - | 721 | 772 |
| NMGC | - | 108 | - | 95 | - | 426 | 629 |
| NMGI | - | 203 | - | - | - | - | 203 |
| NSPI | - | 398 | 125 | 40 | 483 | 2,500 | 3,546 |
| EBP | - | - | - | 249 | - | - | 249 |
| ECI | 74 | 90 | 137 | 85 | 60 | 3 | 449 |
| Total | $574 | $1,613 | $262 | $3,110 | $946 | $9,937 | $16,442 |

#### 26. ASSET RETIREMENT OBLIGATIONS

AROs mostly relate to reclamation of land at the thermal, hydro and combustion turbine sites; and the disposal of polychlorinated biphenyls in transmission and distribution equipment and a pipeline site. Certain hydro, transmission and distribution assets may have additional AROs that cannot be measured as these assets are expected to be used for an indefinite period and, as a result, a reasonable estimate of the fair value of any related ARO cannot be made.

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

| millions of dollars | 2022 | 2021 |
| --- | --- | --- |
| Balance, January 1 | $174 | $178 |
| Accretion included in depreciation expense | 9 | 10 |
| Change in FX rate | 3 | (1) |
| Additions | 1 | 1 |
| Accretion deferred to regulatory asset (included in PP&E) | 1 | (2) |
| Liabilities settled (1) | (1) | (13) |
| Revisions in estimated cash flows | (13) | - |
| Other | - | 1 |
| Balance, December 31 | $174 | $174 |

(1) Tampa Electric produced ash and other by-products, collectively known as CCR's, at its Big Bend and Polk power stations. The decrease in ARO in 2021 was due to the closure of CCR management facilities.

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## 27. COMMITMENTS AND CONTINGENCIES

### A. Commitments

As at December 31, 2022, contractual commitments (excluding pensions and other post-retirement obligations, long-term debt and asset retirement obligations) for each of the next five years and in aggregate thereafter consisted of the following:

| millions of dollars | 2023 | 2024 | 2025 | 2026 | 2027 | Thereafter | Total |
| --- | --- | --- | --- | --- | --- | --- | --- |
| Transportation (1) | $693 | $516 | $423 | $383 | $367 | $2,817 | $5,199 |
| Purchased power (2) | 269 | 243 | 237 | 228 | 243 | 2,145 | 3,365 |
| Fuel, gas supply and storage | 1,161 | 282 | 138 | 40 | 5 | 1 | 1,627 |
| Capital projects | 264 | 89 | 4 | 1 | - | - | 358 |
| Equity investment commitments (3) | 240 | - | - | - | - | - | 240 |
| Other | 149 | 142 | 132 | 49 | 42 | 189 | 703 |
|  | $2,776 | $1,272 | $934 | $701 | $657 | $5,152 | $11,492 |

(1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $144 million related to a gas transportation contract between PGS and SeaCoast through 2040.

(2) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths.

(3) Emera has a commitment to make a final equity contribution to the LIL upon its commissioning. Once commissioned, the commercial agreements between Emera and Nalcor require true ups to finalize the respective investment obligations of the parties in relation to the Maritime Link and LIL.

NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. In February 2022, the UARB issued its decision and Board Order approving NSPML's requested rate base of approximately $1.8 billion. In December 2022, the UARB approved the collection of $164 million from NSPI for the recovery of Maritime Link costs in 2023. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to UARB approval.

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

### B. 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 $38 million USD in full and final satisfaction of the First Award.

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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 $35 million USD plus interest (the 'Second Award'). TGH subsequently requested a reconsideration of the interest quantum awarded in connection with the Second Award. On October 16, 2020, the tribunal granted TGH's request for additional interest. The additional amount was approximately $2 million USD. On February 12, 2021, Guatemala filed an application with ICSID for annulment of the Second Award. On March 31, 2021, ICSID constituted an ad hoc Committee to oversee the annulment proceeding. A three-day hearing was held before the ad hoc Committee beginning on July 27, 2022.

On November 28, 2022, TGH and Guatemala entered into a settlement agreement with respect to the Second Award. Pursuant to the settlement agreement, on December 15, 2022, Guatemala paid TGH $46 million USD and the parties agreed to settle all outstanding disputes, concluding this matter. This amount was recognized in 'Other Income, net' on the Consolidated Statements of Income.

### **Superfund and Former Manufactured Gas Plant Sites**

TEC, through its Tampa Electric and PGS divisions, is a potentially responsible party ('PRP') for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as at December 31, 2022, TEC estimated its financial liability to be $17 million ($13 million USD), primarily at PGS. This estimate assumes that other involved PRPs are credit-worthy entities. This amount has been accrued and is primarily reflected in the long-term liability section under 'Other long-term liabilities' on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.

The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC's experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-worthy and are likely to continue to be credit-worthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC's actual percentage of the remediation costs. Other factors that could impact these estimates include additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in base rate proceedings.

### **Other Legal Proceedings**

Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company.

### **C. 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.

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Sound risk management is an essential discipline for running the business efficiently and pursuing the Company's strategy successfully. Emera has an enterprise-wide risk management process, overseen by its Enterprise Risk Management Committee ('ERMC') and monitored by the Board of Directors, to ensure an effective, consistent and coherent approach to risk management. The Board of Directors established a Risk and Sustainability Committee ('RSC') in September 2021. The RSC's mandate includes oversight of the Company's Enterprise Risk Management framework, including the identification, assessment, monitoring and management of enterprise risks. It also includes oversight of the Company's approach to sustainability and its performance relative to its sustainability objectives.

## Regulatory and Political Risk

The Company's rate-regulated subsidiaries and certain investments subject to significant influence are subject to risk of the recovery of costs and investments. Regulatory and political risk can include changes in regulatory frameworks, shifts in government policy, legislative changes, and regulatory decisions.

As cost-of-service utilities with an obligation to serve customers, Emera's utilities operate under formal regulatory frameworks, and must obtain regulatory approval to change or add rates and/or riders. Emera also holds investments in entities in which it has significant influence, and which are subject to regulatory and political risk including NSPML, LIL, and M&NP. As a regulated Group II pipeline, the tolls of Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to the regulatory approval process described above. In the absence of a complaint, the CER does not normally undertake a detailed examination of Brunswick Pipeline's tolls, which are subject to a firm service agreement expiring in 2034, with Repsol Energy North America Canada Partnership. The agreement provides for a predetermined toll increase in the fifth and fifteenth year of the contract.

Regulators administer legislation covering material aspects of the utilities' businesses, including customer rates and/or riders, the underlying allowed ROEs, deemed capital structures, capital investment, the terms and conditions for the provision of service, performance standards, and affiliate transactions. Costs and investments can be recovered upon approval by the respective regulator as an adjustment to rates and/or riders, which normally requires a public hearing process or may be mandated by other governmental bodies. During public hearing processes, consultants and customer representatives scrutinize the costs, actions and plans of these rate-regulated companies, and their respective regulators determine whether to allow recovery and to adjust rates based upon the evidence and any contrary evidence from other parties. In some circumstances, other government bodies may influence the setting of rates. Regulatory decisions, legislative changes, and prolonged delays in the recovery of costs or regulatory assets could result in decreased rate affordability for customers and could materially affect Emera and its utilities.

Emera's utilities generally manage this risk through transparent regulatory disclosure, ongoing stakeholder and government consultation and multi-party engagement on aspects such as utility operations, regulatory audits, rate filings and capital plans. The subsidiaries employ a collaborative regulatory approach through technical conferences and, where appropriate, negotiated settlements.

Changes in government and shifts in government policy and legislation can impact the commercial and regulatory frameworks under which Emera and its subsidiaries operate. This includes initiatives regarding deregulation or restructuring of the energy industry. Deregulation or restructuring of the energy industry may result in increased competition and unrecovered costs that could adversely affect operations, net income and cash flows. State and local policies in some United States jurisdictions have sought to prevent or limit the ability of utilities to provide customers the choice to use natural gas while in other jurisdictions policies have been adopted to prevent limitations on the use of natural gas. Changes in applicable state or local laws and regulations, including electrification legislation, could adversely impact PGS and NMGC.

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Emera cannot predict future legislative, policy, or regulatory changes, whether caused by economic, political or other factors, or its ability to respond in an effective and timely manner or the resulting compliance costs. Government interference in the regulatory process can undermine regulatory stability, predictability, and independence, and could have a material adverse effect on the Company.

### **Foreign Exchange Risk**

The Company is exposed to foreign currency exchange rate changes. Emera operates internationally, with an increasing amount of the Company's net income earned outside of Canada. As such, Emera is exposed to movements in exchange rates between the CAD and, particularly, the USD, which could positively or adversely affect results.

Consistent with the Company's risk management policies, Emera manages currency risks through matching United States denominated debt to finance its United States operations and may use foreign currency derivative instruments to hedge specific transactions and earnings exposure. The Company may enter FX forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases, revenue streams and capital expenditures, and on net income earned outside of Canada. The regulatory framework for the Company's rate-regulated subsidiaries permits the recovery of prudently incurred costs, including FX.

The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries do not impact net income as they are reported in AOCI.

### **Liquidity and Capital Market Risk**

Liquidity risk relates to Emera's ability to ensure sufficient funds are available to meet its financial obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity and capital needs could be financed through internally generated cash flows, asset sales, short-term credit facilities, and ongoing access to capital markets.

Emera's access to capital and cost of borrowing is subject to several risk factors, including financial market conditions, market disruptions, and ratings assigned by credit rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or cause the Company to issue securities with less than preferred terms and conditions. Emera's growth plan requires significant capital investments in PP&E and the risk associated with changes in interest rates could have an adverse effect on the cost of financing. The Company's future access to capital and cost of borrowing may be impacted by various market disruptions. The inability to access cost-effective capital could have a material impact on Emera's ability to fund its growth plan.

Emera is subject to financial risk associated with changes in its credit ratings. There are a number of factors that rating agencies evaluate to determine credit ratings, including the Company's business, its regulatory framework and the legislative environment, political interference in the regulatory process, the ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to climate change-related impacts, including increased frequency and severity of hurricanes and other severe weather events. A decrease in a credit rating could result in higher interest rates in future financings, increased borrowing costs under certain existing credit facilities, limit access to the commercial paper market or limit the availability of adequate credit support for subsidiary operations. For certain derivative instruments, if the credit ratings of the Company were reduced below investment grade, the full value of the net liability of these positions could be required to be posted as collateral. Emera manages these risks by actively monitoring and managing key financial metrics with the objective of sustaining investment grade credit ratings.

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

### General Economic Risk

The Company has exposure to the macro-economic conditions in North America and in other geographic regions in which Emera operates. Like most utilities, economic factors such as consumer income, employment and housing affect demand for electricity and natural gas, and in turn the Company's financial results. Adverse changes in general economic conditions and inflation may impact the ability of customers to afford rate increases arising from increases to fuel, operating, capital, environmental compliance, and other costs, and therefore could materially affect Emera and its utilities. This may also result in higher credit and counterparty risk, adverse shifts in government policy and legislation, and/or increased risk to full and timely recovery of costs and regulatory assets.

#### *Interest Rate Risk*

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

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

As with most other utilities and other similar yield-returning investments, Emera's share price may be affected by changes in interest rates and could underperform the market in an environment of rising interest rates.

#### *Inflation Risk*

The Company may be exposed to changes in inflation that may result in increased operating and maintenance costs, capital investment, and fuel costs compared to the revenues provided by customer rates. Emera's utilities have budgeting and forecasting processes to identify inflationary risk factors and measure operating performance, as well as collective bargaining agreements that mitigate the short-term impact of inflation on labour costs.

### Commodity Price Risk

The Company's utility fuel supply is subject to commodity price risk. In addition, Emera Energy is subject to commodity price risk through its portfolio of commodity contracts and arrangements.

The Company manages this risk through established processes and practices to identify, monitor, report and mitigate these risks. These include the Company's commercial arrangements, such as the combination of supply and purchase agreements, asset management agreements, pipeline transportation agreements and financial hedging instruments. In addition, its credit policies, counterparty credit assessments, market and credit position reporting, and other risk management and reporting practices, are also used to manage and mitigate this risk.

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### *Regulated Utilities*

The Company's utility fuel supply is exposed to broader global conditions, which may include impacts on delivery reliability and price, despite contracted terms. Supply and demand dynamics in fuel markets can be affected by a wide range of factors which are difficult to predict and may change rapidly, including but not limited to currency fluctuations, changes in global economic conditions, natural disasters, transportation or production disruptions, and geo-political risks such as political instability, conflicts, changes to international trade agreements, trade sanctions or embargos. The Company seeks to manage this risk using financial hedging instruments and physical contracts and through contractual protection with counterparties, where applicable.

The majority of Emera's regulated electric and gas utilities have adopted and implemented fuel adjustment mechanisms and purchased gas adjustment mechanisms respectively, which has further helped manage commodity price risk, as the regulatory framework for the Company's rate-regulated subsidiaries permits the recovery of prudently incurred fuel and gas costs. There is no assurance that such mechanisms and regulatory frameworks will continue to exist in the future. Prolonged and substantial increases in fuel prices could result in decreased rate affordability, increased risk of recovery of costs or regulatory assets, and/or negative impacts on customer consumption patterns and sales.

### *Emera Energy Marketing and Trading*

Emera Energy has employed further measures to manage commodity risk. The majority of Emera Energy's portfolio of electricity and gas marketing and trading contracts and, in particular, its natural gas asset management arrangements, are contracted on a back-to-back basis, avoiding any material long or short commodity positions. However, the portfolio is subject to commodity price risk, particularly with respect to basis point differentials between relevant markets in the event of an operational issue or counterparty default. Changes in commodity prices can also result in increased collateral requirements associated with physical contracts and financial hedges, resulting in higher liquidity requirements and increased costs to the business.

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.

### **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.

### **D. Guarantees and Letters of Credit**

Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December 31, 2022:

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TECO Energy has issued a guarantee in connection with SeaCoast's performance of obligations under a gas transportation precedent agreement. The guarantee is for a maximum potential amount of $45 million USD if SeaCoast fails to pay or perform under the contract. The guarantee expires five years after the gas transportation precedent agreement termination date, which was terminated on January 1, 2022. In the event that TECO Energy's and Emera's long-term senior unsecured credit ratings are downgraded below investment grade by Moody's Investor Services ('Moody's') or S&P Global Ratings ('S&P'). TECO Energy would be required to provide its counterparty a letter of credit or cash deposit of $27 million USD.

TECO Energy issued a guarantee in connection with SeaCoast's performance obligations under a firm service agreement, which expires on December 31, 2055, subject to two extension terms at the option of the counterparty with a final expiration date of December 31, 2071. The guarantee is for a maximum potential amount of $13 million USD if SeaCoast fails to pay or perform under the firm service agreement. In the event that TECO Energy's long-term senior unsecured credit ratings are downgraded below investment grade by Moody's or S&P, TECO Energy would need to provide either a substitute guarantee from an affiliate with an investment grade credit rating or a letter of credit or cash deposit of $13 million USD.

Emera Inc. has issued a guarantee of up to $35 million USD relating to outstanding notes of GBPC. The guarantee for the notes will expire in May 2023.

Emera Inc. has issued a guarantee of $66 million USD relating to outstanding notes of ECI. This guarantee will automatically terminate on the date upon which the obligations have been repaid in full.

NSPI has issued guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated ('NSPEMI'), in the amount of $119 million USD (2021 - $118 million USD) with terms of varying lengths.

The Company has standby letters of credit and surety bonds in the amount of $145 million USD (December 31, 2020 - $148 million USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed annually as required.

Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The expiry date of this letter of credit was extended to June 2023. The amount committed as at December 31, 2022 was $63 million (December 31, 2021 - $64 million).

## Collaborative Arrangements

For the years ended December 31, 2022 and 2021, the Company has identified the following material collaborative arrangements:

Through NSPI, the Company is a participant in three wind energy projects in Nova Scotia. The percentage ownership of the wind project assets is based on the relative value of each party's project assets by the total project assets. NSPI has power purchase arrangements to purchase the entire net output of the projects and, therefore, NSPI's portion of the revenues are recorded net within regulated fuel for generation and purchased power. NSPI's portion of operating expenses is recorded in OM&G. In 2022, NSPI recognized $12 million net expense (2021 - $18 million) in 'Regulated fuel for generation and purchased power' and $3 million (2021 - $3 million) in OM&G.

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## 28. CUMULATIVE PREFERRED STOCK

### Authorized:

Unlimited number of First Preferred shares, issuable in series.

Unlimited number of Second Preferred shares, issuable in series.

|  | December 31, 2022 |  |  | December 31, 2021 |  |  |
| --- | --- | --- | --- | --- | --- | --- |
|  | Annual Dividend Per Share | Redemption Price per share | Issued and Outstanding | Net Proceeds | Issued and Outstanding | Net Proceeds |
| Series A | $0.5456 | $25.00 | 4,866,814 | $119 | 4,866,814 | $119 |
| Series B | Floating | $25.00 | 1,133,186 | $28 | 1,133,186 | $28 |
| Series C | $1.1802 | $25.00 | 10,000,000 | $245 | 10,000,000 | $245 |
| Series E | $1.1250 | $25.00 | 5,000,000 | $122 | 5,000,000 | $122 |
| Series F | $1.0505 | $25.00 | 8,000,000 | $195 | 8,000,000 | $195 |
| Series H | $1.2250 | $25.00 | 12,000,000 | $295 | 12,000,000 | $295 |
| Series J | $1.0625 | $25.00 | 8,000,000 | $196 | 8,000,000 | $196 |
| Series L | $1.1500 | $26.00 | 9,000,000 | $222 | 9,000,000 | $222 |
| Total |  |  | 58,000,000 | $1,422 | 58,000,000 | $1,422 |

### Characteristics of the First Preferred Shares:

| First Preferred Shares (1)(2) | Initial Yield (%) | Current Annual Dividend ($) | Minimum Reset Dividend Yield (%) | Earliest Redemption and/or Conversion Option Date | Redemption Value ($) | Right to Convert on a one for one basis |
| --- | --- | --- | --- | --- | --- | --- |
| Fixed rate reset (3)(4) |  |  |  |  |  |  |
| Series A | 4.400 | 0.5456 | 1.84 | August 15, 2025 | 25.00 | Series B |
| Series C | 4.100 | 1.1802 | 2.65 | August 15, 2023 | 25.00 | Series D |
| Series F | 4.202 | 1.0505 | 2.63 | February 15, 2025 | 25.00 | Series G |
| Minimum rate reset (3)(4) |  |  |  |  |  |  |
| Series B | 2.393 | Floating | 1.84 | August 15, 2025 | 25.00 | Series A |
| Series H | 4.900 | 1.2250 | 4.90 | August 15, 2023 | 25.00 | Series I |
| Series J | 4.250 | 1.0625 | 4.25 | May 15, 2026 | 25.00 | Series K |
| Perpetual fixed rate |  |  |  |  |  |  |
| Series E (5) | 4.500 | 1.1250 |  |  | 25.00 |  |
| Series L (6) | 4.600 | 1.1500 |  | November 15, 2026 | 26.00 |  |

(1) Holders are entitled to receive fixed or floating cumulative cash dividends when declared by the Board of Directors of the Corporation.

(2) On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding First Preferred Shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but excluding the dates fixed for redemption.

(3) On the redemption and/or conversion option date the reset annual dividend per share will be determined by multiplying $25.00 per share by the annual fixed or floating dividend rate, which for Series A, C, F and H is the sum of the five-year Government of Canada Bond Yield on the applicable reset date, plus the applicable reset dividend yield (Series H annual reset rate must be a minimum of 4.90 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 $25.00 per share.

(6) First Preferred Shares, Series L are redeemable at $26.00 on or after November 15, 2026 to November 15, 2027, decreasing $0.25 each year until November 15, 2030 and $25.00 per share thereafter.

First Preferred Shares are neither redeemable at the option of the shareholder nor have a mandatory redemption date. They are classified as equity and the associated dividends are deducted on the Consolidated Statements of Income before arriving at 'Net income attributable to common shareholders' and shown on the Consolidated Statement of Equity as a deduction from retained earnings.

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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 millions of dollars | December 31 2022 | December 31 2021 |
| --- | --- | --- |
| Preferred shares of GBPC | $14 | $14 |
| Domlec (1) | - | 20 |
|  | $14 | $34 |

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

### Preferred shares of GBPC:

#### Authorized:

10,000 non-voting cumulative redeemable variable perpetual preferred shares.

| Issued and outstanding: | 2022 |  | 2021 |  |
| --- | --- | --- | --- | --- |
|  | number of shares | millions of dollars | number of shares | millions of dollars |
| Outstanding as at December 31 | 10,000 | $14 | 10,000 | $14 |

### 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.

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### 30. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS

| For the millions of dollars | Year ended December 31 |  |
| --- | --- | --- |
|  | 2022 | 2021 |
| Changes in non-cash working capital: |  |  |
| Inventory | $(214) | $(84) |
| Receivables and other current assets (1) | (636) | (364) |
| Accounts payable | 423 | 289 |
| Other current liabilities (2) | 193 | 7 |
| Total non-cash working capital | $(234) | $(152) |

(1) Includes $(162) million related to the January 2023 settlement of NMGC gas hedges. Offsetting regulatory liability is included in operating cash flow before working capital resulting in no impact to net cash provided by operating activities.

(2) Includes $172 million related to the Nova Scotia Cap-and-Trade program. For further detail, refer to note 7. Offsetting regulatory asset (FAM) balance is included in operating cash flow before working capital resulting in no impact to net cash provided by operating activities.

#### Supplemental disclosure of cash paid (received):

| Interest | $699 | $603 |
| --- | --- | --- |
| Income taxes | $67 | $24 |

#### Supplemental disclosure of non-cash activities:

| Common share dividends reinvested | $237 | $214 |
| --- | --- | --- |
| Reclassification of long-term debt to short-term debt | $500 | $ - |
| Decrease in accrued capital expenditures | $(13) | $(45) |

#### Supplemental disclosure of operating activities:

| Net change in short-term regulatory assets and liabilities | $(157) | $(108) |
| --- | --- | --- |

### 31. STOCK-BASED COMPENSATION

#### Employee Common Share Purchase Plan and Common Shareholders Dividend Reinvestment and Share Purchase Plan

Eligible employees may participate in Emera's Employee Common Share Purchase Plan. As of December 31, 2022, the plan allows employees to make cash contributions of a minimum of $25 to a maximum of $20,000 CAD or $15,000 USD per year for the purpose of purchasing common shares of Emera. The Company also contributes 20 per cent of the employees' contributions to the plan.

The plan allows the reinvestment of dividends for all participants except for where it is prohibited by law. The maximum aggregate number of Emera common shares reserved for issuance under this plan is 7 million common shares. As at December 31, 2022, Emera is in compliance with this requirement.

Compensation cost for shares issued under the Employee Common Share Purchase Plan for the year ended December 31, 2022 was $3 million (2021 - $3 million) and is included in OM&G on the Consolidated Statements of Income.

The Company also has a Common Shareholders Dividend Reinvestment and Share Purchase Plan ('Dividend Reinvestment Plan'), which provides an opportunity for shareholders to reinvest dividends and purchase common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera's common shares for common shares purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2022.

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## Stock-Based Compensation Plans

### Stock Option Plan

The Company has a stock option plan that grants options to senior management of the Company for a maximum term of 10 years. The option price of the stock options is the closing price of the Company's common shares on the Toronto Stock Exchange on the last business day on which such shares were traded before the date on which the option is granted. The maximum aggregate number of shares issuable under this plan is 14.7 million shares. As at December 31, 2022, Emera is in compliance with this requirement.

Stock options granted in 2021 and prior vest in 25 per cent increments on the first, second, third and fourth anniversaries of the date of the grant. Stock options granted in 2022 vest in 20 per cent increments on the first, second, third, fourth and fifth anniversaries of the date of the grant. If an option is not exercised within 10 years, it expires and the optionee loses all rights thereunder. The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued. The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding common stocks on the date the option is granted.

For stock options granted in 2021 and prior, unless a stock option has expired, vested options may be exercised within the 27 months following the option holders date of retirement, six months following a termination without just cause or death, and within sixty days following the date of termination for just cause or resignation. Commencing with the 2022 stock option grant, vested options may be exercised during the full term of the option following the option holders date of retirement, six months following a termination without just cause or death, and within sixty days following the date of termination for just cause or resignation. If stock options are not exercised within such time, they expire.

The Company uses the Black-Scholes valuation model to estimate the compensation expense related to its stock-based compensation and recognizes the expense over the vesting period on a straight-line basis.

The following table shows the weighted average fair values per stock option along with the assumptions incorporated into the valuation models for options granted, for the year-ended December 31:

|  | 2022 | 2021 |
| --- | --- | --- |
| Weighted average fair value per option | $5.35 | $3.63 |
| Expected term (1) | 5 years | 5 years |
| Risk-free interest rate (2) | 1.79% | 0.60% |
| Expected dividend yield (3) | 4.55% | 5.00% |
| Expected volatility (4) | 18.87% | 19.14% |

(1) The expected term of the option awards is calculated based on historical exercise behaviour and represents the period of time that the options are expected to be outstanding.

(2) Based on the Bank of Canada five-year government bond yields.

(3) Incorporates current dividend rates and historical dividend increase patterns.

(4) Estimated using the five-year historical volatility.

The following table summarizes stock option information for 2022:

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|  | Total Options |  | Non-Vested Options(1) |  |
| --- | --- | --- | --- | --- |
|  | Number of Options | Weighted average exercise price per share | Number of Options | Weighted average grant date fair-value |
| Outstanding as at December 31, 2021 | 2,590,304 | $48.48 | 1,452,475 | $3.18 |
| Granted | 467,100 | 58.26 | 467,100 | 5.35 |
| Exercised | (203,525) | 43.87 | N/A | N/A |
| Vested | N/A | N/A | (571,175) | 2.83 |
| Options outstanding December 31, 2022 | 2,853,879 | $50.41 | 1,348,400 | $4.08 |
| Options exercisable December 31, 2022 (2)(3) | 1,505,479 | $46.59 |  |  |

(1) As at December 31, 2022, there was $4 million of unrecognized compensation related to stock options not yet vested which is expected to be recognized over a weighted average period of approximately 3 years (2021 - $3 million, 3 years).

(2) As at December 31, 2022, the weighted average remaining term of vested options was 5 years with an aggregate intrinsic value of $10 million (2021 - 6 years, $21 million).

(3) As at December 31, 2022, the fair value of options that vested in the year was $2 million (2021 - $1 million).

Compensation cost recognized for stock options for the year ended December 31, 2022 was $2 million (2021 - $2 million), which is included in OM&G on the Consolidated Statements of Income.

As at December 31, 2022, cash received from option exercises was $9 million (2021 - $14 million). The total intrinsic value of options exercised for the year ended December 31, 2022 was $4 million (2021 - $6 million). The range of exercise prices for the options outstanding as at December 31, 2022 was $32.35 to $60.03 (2021 - $32.35 to $60.03).

## Share Unit Plans

The Company has DSU, PSU and RSU plans. The plans and the liabilities are marked-to-market at the end of each period based on an average common share price at the end of the period.

### Deferred Share Unit Plans

Under the Directors' DSU plan, Directors of the Company may elect to receive all or any portion of their compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum portion of their annual retainer in DSUs. Directors' fees are paid on a quarterly basis and, at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one Emera common share. When a dividend is paid on Emera's common shares, the Director's DSU account is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns or otherwise leaves the Board. The cash redemption value of a DSU equals the market value of a common share at the time of redemption, pursuant to the plan. Following retirement or resignation from the Board, the value of the DSUs credited to the participant's account is calculated by multiplying the number of DSUs in the participant's account by Emera's closing common share price on the date DSUs are redeemed.

Under the executive and senior management DSU plan, each participant may elect to defer all or a percentage of their annual incentive award in the form of DSUs with the understanding, for participants who are subject to executive share ownership guidelines, a minimum of 50 per cent of the value of their actual annual incentive award (25 per cent in the first year of the program) will be payable in DSUs until the applicable guidelines are met.

When short-term incentive awards are determined, the amount elected is converted to DSUs, which have a value equal to the market price of an Emera common share. When a dividend is paid on Emera's common shares, each participant's DSU account is allocated additional DSUs equal in value to the dividends paid on an equivalent number of Emera common shares. Following termination of employment or retirement, and by December 15 of the calendar year after termination or retirement, the value of the DSUs credited to the participant's account is calculated by multiplying the number of DSUs in the participant's account by the average of Emera's stock closing price for the fifty trading days prior to a given calculation date. Payments are made in cash.

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In addition, special DSU awards may be made from time to time by the Management Resources and Compensation Committee ('MRCC'), to selected executives and senior management to recognize singular achievements or by achieving certain corporate objectives.

A summary of the activity related to employee and director DSUs for the year ended December 31, 2022 is presented in the following table:

|  | Employee DSU | Weighted Average Grant Date Fair Value | Director DSU | Weighted Average Grant Date Fair Value |
| --- | --- | --- | --- | --- |
| Outstanding as at December 31, 2021 | 610,601 | $39.22 | 614,365 | $43.80 |
| Granted including DRIP | 76,252 | 52.42 | 104,465 | 57.89 |
| Exercised | (59,630) | 31.57 | (54,572) | 46.04 |
| Outstanding and exercisable as at December 31, 2022 | 627,223 | $41.55 | 664,258 | $45.83 |

Compensation cost recovery recognized for employee and director DSU's for the year ended December 31, 2022 was $6 million (2021 - $9 million expense). Tax expense related to this compensation cost recovery for share units realized for the year ended December 31, 2022 was $2 million (2021 - $3 million tax recovery). The aggregate intrinsic value of the outstanding shares for the year ended December 31, 2022 for employees was $33 million (2021 - $39 million). The aggregate intrinsic value of the outstanding shares for the year ended December 31, 2022 for directors was $34 million (2021 - $39 million). Cash payments made during the year ended December 31, 2021 associated with the DSU plan was $8 million (2021 - $11 million).

#### Performance Share Unit Plan

Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable through the PSU plan. PSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. PSUs are granted based on the average of Emera's stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional PSUs. The PSU value varies according to the Emera common share market price and corporate performance.

PSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios.

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

|  | Employee PSU | Weighted Average Grant Date Fair Value | Aggregate intrinsic value |
| --- | --- | --- | --- |
| Outstanding as at December 31, 2021 | 951,935 | $48.60 | $66 |
| Granted including DRIP | 242,462 | 59.30 |  |
| Exercised | (357,960) | 42.85 |  |
| Forfeited | (145,991) | 44.28 |  |
| Outstanding as at December 31, 2022 | 690,446 | $56.24 | $40 |

Compensation cost recognized for the PSU plan for the year ended December 31, 2022 was $18 million (2021 - $12 million). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2022 were $5 million (2021 - $3 million). Cash payments made during the year ended December 31, 2021 associated with the PSU plan was $24 million (2021 - $29 million).

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## Restricted Share Unit Plan

Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable through the RSU plan. RSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. RSUs are granted based on the average of Emera's stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional RSUs. The RSU value varies according to the Emera common share market price.

RSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios.

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

|  | Employee RSU | Weighted Average Grant Date Fair Value | Aggregate intrinsic value |
| --- | --- | --- | --- |
| Outstanding as at December 31, 2021 | 343,952 | $54.64 | $24 |
| Granted including DRIP | 180,426 | 59.30 |  |
| Exercised | (134) | 54.63 |  |
| Forfeited | (15,776) | 56.08 |  |
| Outstanding as at December 31, 2022 | 508,468 | $56.25 | $30 |

Compensation cost recognized for the RSU plan for the year ended December 31, 2022 was $9 million (2021 - $8 million). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2022 were $2 million (2021 - $2 million). Cash payments made during the year ended December 31, 2022 associated with the RSU plan was nil (2021- nil).

## 32. VARIABLE INTEREST ENTITIES

Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since it does not have the controlling financial interest of NSPML. When the critical milestones were achieved, Nalcor Energy was deemed the primary beneficiary of the asset for financial reporting purposes as it has authority over the majority of the direct activities that are expected to most significantly impact the economic performance of the Maritime Link. Thus, Emera began recording the Maritime Link as an equity investment.

BLPC has established a Self-Insurance Fund ('SIF'), primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission and distribution systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered that, in substance, the activities of the SIF are being conducted on behalf of ECI's subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF's operations. Additionally, because ECI, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. Any withdrawal of SIF fund assets by the Company would be subject to existing regulations. Emera's consolidated VIE in the SIF is recorded as 'Other long-term assets', 'Restricted cash' and 'Regulatory liabilities' on the Consolidated Balance Sheets. Amounts included in restricted cash represent the cash portion of funds required to be set aside for the BLPC SIF.

The Company has identified certain long-term purchase power agreements that meet the definition of variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions.

The following table provides information about Emera's portion of material unconsolidated VIEs:

77

| As at | December 31, 2022 |  | December 31, 2021 |  |
| --- | --- | --- | --- | --- |
| millions of dollars | Total assets | Maximum exposure to loss | Total assets | Maximum exposure to loss |
| Unconsolidated VIEs in which Emera has variable interests |  |  |  |  |
| NSPML (equity accounted) | $501 | $6 | $533 | $11 |

### 33. COMPARATIVE INFORMATION

These financial statements contain certain reclassifications of prior period amounts to be consistent with the current period presentation, with no effect on net income.

### 34. SUBSEQUENT EVENTS

These financial statements and notes reflect the Company's evaluation of events occurring subsequent to the balance sheet date through February 23, 2023, the date the financial statements were issued.

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## Exhibit 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 23, 2023, with respect to the consolidated balance sheets of Emera Incorporated as at December 31, 2022 and 2021, 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 24, 2023 |  |

---

## Exhibit 99.5

**Exhibit 99.5** 

**<u>CERTIFICATION</u>**

I, Scott C. Balfour, certify that:

1. I have reviewed this annual report on Form 40-F of Emera Incorporated;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
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,
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
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:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
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
prepared;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b) Designed such internal control over financial reporting, or caused such internal control over financial
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
principles;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c) Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this
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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;d) Disclosed in this report any change in the issuer's internal control over financial reporting that
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
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):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a) All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b) Any fraud, whether or not material, that involves management or other employees who have a significant role in
the issuer's internal control over financial reporting.

---

| |
|:---|
| Date: February 24, 2023 |
| <u>/s/ Scott C. Balfour</u> |
| Scott C. Balfour |
| President & Chief Executive Officer |

---

## Exhibit 99.6

**Exhibit 99.6** 

**<u>CERTIFICATION</u>**

I, Gregory W. Blunden, certify that:

1. I have reviewed this annual report on Form 40-F of Emera Incorporated;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
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,
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
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:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
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
prepared;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b) Designed such internal control over financial reporting, or caused such internal control over financial
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
principles;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c) Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this
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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;d) Disclosed in this report any change in the issuer's internal control over financial reporting that
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
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):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a) All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b) Any fraud, whether or not material, that involves management or other employees who have a significant role in
the issuer's internal control over financial reporting.

---

| |
|:---|
| Date: February 24, 2023 |
| <u>/s/ Gregory W. Blunden</u> |
| Gregory W. Blunden |
| Chief Financial Officer |

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## Exhibit 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, 2022 (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:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the U.S. Securities Exchange
Act of 1934; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and
results of operations of the Company.

---

| |
|:---|
| &nbsp;&nbsp;&nbsp;&nbsp;Date: February 24, 2023 |
| <u>/s/ Scott C. Balfour</u> |
| &nbsp;&nbsp;&nbsp;&nbsp;Scott C. Balfour |
| &nbsp;&nbsp;&nbsp;&nbsp;President & Chief Executive Officer |

---

## Exhibit 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

In connection with the annual report of Emera Incorporated (the "Company") on Form 40-F for the year ended December 31, 2022 (the "Report") as filed with the U.S. Securities and Exchange Commission,

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:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the U.S. Securities Exchange
Act of 1934; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and
results of operations of the Company.

---

| |
|:---|
| Date: February 24, 2023 |
| <u>/s/ Gregory W. Blunden</u> |
| Gregory W. Blunden |
| Chief Financial Officer |

---