Emera (EMRAF) 40-F2023 FY Annual report (Canada)

Exhibit 99.1

Emera Incorporated

Annual Information Form

For the year ended December 31, 2023

February 26, 2024

ANNUAL INFORMATION FORM

For the year ended December 31, 2023

Dated: February 26, 2024

TABLE OF CONTENTS

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, 2023. 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 www.sedarplus.ca.

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

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

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 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; changes in credit ratings; 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 risk, including higher frequency and severity of weather events; risk of wildfires; 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; supply chain risk; environmental risks; foreign exchange (“FX”); regulatory and government decisions, including changes to environmental legislation, 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; 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.

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 www.sedarplus.ca.

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, 2023.

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 investments 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 approximately $9 billion over the 2024 through 2026 period with approximately $2 billion of additional potential capital investments over the same period. The capital investment plan and additional potential capital result in an anticipated compound annual rate base growth in the range of approximately 7 per cent to 8 per cent through 2026. The capital investment plan includes significant investments across the portfolio in renewable and cleaner generation, reliability and system integrity investments, infrastructure modernization, infrastructure expansion to meet the needs of new and existing customers, and technologies to better support the business and customer experiences. It is

anticipated that approximately 75 per cent of Emera’s $9 billion capital investment plan over the 2024 through 2026 period will be made in Florida.

Emera’s capital investment plan is being funded primarily through internally generated cash flows, debt raised at the operating company level consistent with regulated capital structures, equity, and select asset sales. Generally, 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 2026. 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 www.sedarplus.ca.

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 CAD. 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 experiencing significant change and Emera is well-positioned to continue to respond to shifting customer demands and meet the challenges of digitization, decarbonization and decentralized generation, within complex regulatory environments.

Customers depend on energy and are looking for more choice, better control, and greater reliability. The costs of decentralized generation and storage have become more competitive and advancing technologies are transforming how utilities operate and interact with customers. Concurrently, climate change and the increased frequency of extreme weather events are shaping government energy policy. This is also creating a need to replace aging infrastructure and make investments to protect and harden energy systems to deliver energy reliability and system resiliency. These factors combined with inflation, higher interest rates and higher cost of capital place increased pressure on energy costs, and thus customer rates, at a time when affordability is a challenge.

Emera’s strategy is to invest in the energy future, including infrastructure renewal, centered on delivering value for customers, and in doing so creating value for shareholders. This includes:

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 visible 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:

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:

General

Emera and its subsidiaries had 7,366 employees as at December 31, 2023, approximately 30 per cent of whom are unionized.

Operations by Segment

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

Florida Electric Utility

Florida Electric Utility consists of TEC, a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity, serving customers in West Central Florida. TEC has $12 billion USD of assets, approximately 840,000 customers and 2,546 employees as at December 31, 2023.

TEC 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 TEC 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 TEC, the FPSC or other interested parties.

TEC’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 is used for the calculation of the return on investments for clauses.

For further details on TEC’s regulatory environment, base rates and recovery mechanisms, refer to Note 6, 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 www.sedarplus.ca.

Market and Sales

Energy Sources and Generation

As at December 31, 2023, TEC owns 6,433 MW of generating capacity, of which 74 per cent is natural gas fired, 19 per cent is solar and 7 per cent is coal. TEC owns 2,192 kilometres of transmission facilities and 20,299 kilometres of distribution facilities. TEC 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

TEC’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, TEC’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, TEC has immediate access to reserve generating capacity from all other group members.

Contribution to Consolidated Net Income

Florida Electric Utility’s contribution to consolidated net income was $466 million USD in 2023 (2022 – $458 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 2023, capital investments, including AFUDC, in the Florida Electric Utility segment were $1.3 billion USD (2022 – $1.1 billion USD). In 2024, capital investment is expected to be approximately $1.3 billion USD, including AFUDC. Capital projects include solar investments, grid modernization, storm hardening investments and other infrastructure investments.

Environmental Considerations

TEC has significant environmental considerations. TEC 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 TEC’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, TEC 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”). EPA released a proposed rule establishing CO₂ emission standards for new and existing fossil fuel-fired power plants. As proposed under Section 111 of the Clean Air Act, the New Source Performance Standards and Best System of Emission Reduction guidelines would require affected electric generating units to achieve CO₂ emission limits thorough the implementation of carbon capture and sequestration, or low-GHG hydrogen co-firing. The proposed rule also repeals the ACE rule promulgated under the Trump Administration. TEC expects one or more units to be subject to the rule, if finalized in its current form.

TEC expects that the costs to comply with new environmental regulations would be eligible for recovery through the ECRC. If approved as prudent, the costs required to comply with CO₂ emissions reductions would be reflected in customers’ bills. If the regulation allowing cost recovery is changed and the cost of compliance is not recovered through the ECRC, TEC 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 TEC’s service territory. The impact of this potential new standard on the operations of TEC will depend on the standard that is ultimately adopted and on the outcome of any related litigation or other developments.

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 TEC’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. TEC 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 TEC’s proposed plan for Bayside and TEC 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. TEC 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 TEC 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 proposed a new rule in March 2023 to strengthen discharge limits that is expected to be finalized in 2024.

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 completed 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.

Superfund and Former Manufactured Gas Plant Sites

Previously, TEC had been a potentially responsible party (“PRP”) for certain superfund sites through its Tampa Electric and former PGS divisions, as well as for certain former manufactured gas plant sites through its PGS division. As a result of the separation of the PGS division into a separate legal entity, PGS is also now a PRP for those sites (in addition to third party PRPs for certain sites). For further details, refer to Note 27, Commitments and Contingencies – Legal Proceedings - Superfund and Former Manufactured Gas Plant Sites, 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 www.sedarplus.ca.

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 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 549,000 customers with $7.2 billion in assets and 2,179 employees as at December 31, 2023.

NSPI is a public utility as defined in the Public Utilities Act and is subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings held from time to time at NSPI’s or the UARB’s request.

NSPI has a FAM, approved by the UARB, allowing NSPI to recover fluctuating fuel and certain fuel-related 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.

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.

For further details on NSPI’s regulatory environment and recovery mechanisms, refer to Note 6, 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 www.sedarplus.ca.

Market and Sales

Energy Sources and Generation

NSPI owns 2,422 MW of generating capacity, of which 44 per cent is coal and/or oil-fired, 28 per cent is natural gas and/or oil, 19 per cent is hydro, wind, or solar, 7 per cent is petroleum coke and 2 per cent is biomass-fueled generation. In addition, NSPI has contracts to purchase renewable energy from IPPs, and COMFIT participants, which own 532 MW of capacity. NSPI also has rights to 153 MW of Maritime Link capacity, representing Nalcor’s NS Block delivery obligations, as discussed below.

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. 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.

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 software applicaction used by system operators for remote monitoring and control of the power system assets via the company’s telecommunication networks.

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 bulk electric 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.

NSPI is a member of the NPCC, a body whose primary role is promoting the reliability of the interconnected power systems throughout the Northeastern United States and Eastern Canada (Nova Scotia, New Brunswick, Quebec, Ontario) under the regulatory authority of NERC. NERC and NPCC reliability standards and criteria are approved for enforcement in Nova Scotia by the UARB. NSPI complies with NPCC criteria and NERC standards for the design, planning and operation of NSPI’s portion of the interconnected bulk electric system.

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 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.

LIL

ENL is a limited partner with Nalcor in LIL. Construction of the LIL is complete and the Newfoundland Electrical System Operator confirmed the asset to be operating suitably to support reliable system operation and full functionality at 700MW, which was validated by the Government of Canada’s Independent Engineer issuing its Commissioning Certificate on April 13, 2023.

Upon issuance of the Commissioning Certificate, AFUDC equity earnings ceased and cash equity earnings and return of equity to Emera commenced. The first distribution was received from the LIL partnership in Q4 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 $747 million, comprised of $410 million in equity contribution and $337 million of accumulated equity earnings. Emera’s total equity contribution in the LIL, excluding accumulated equity earnings, is estimated to be approximately $650 million once the final costing has been confirmed by Nalcor to determine the amount of the remaining investment.

Contribution to Consolidated Net Income and Adjusted Net Income

Canadian Electric Utilities’ contribution to consolidated net income was $247 million in 2023 (2022 - $215 million). Canadian Electric Utilities’ contribution to Emera’s consolidated adjusted net income was $247 million in 2023 (2022 - $222 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 www.sedarplus.ca.

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 2023 were $451 million (2022 – $540 million), including AFUDC. In 2024, NSPI expects to invest $435 million, including AFUDC, primarily in capital projects to support power system reliability and reliable service for customers.

NSPML

NSPML does not anticipate any significant capital investment in 2024.

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 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.sedarplus.ca.

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 also NSPI’s 2023 Annual Information Form, a copy of which is available electronically under NSPI’s profile on SEDAR+ at www.sedarplus.ca.

Gas Utilities and Infrastructure

Gas Utilities and Infrastructure includes PGS, NMGC, SeaCoast, Brunswick Pipeline and Emera’s equity 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.

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

PGS

As at December 31, 2023, PGS serves approximately 490,000 customers with $2.8 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 2023.

PGS is regulated by the FPSC. 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.

Beginning in 2024, the approved ROE range for PGS is 9.15 per cent to 11.15 per cent (2023 – 8.9 per cent to 11.0 per cent), based on an allowed equity capital structure of 54.7 per cent (2023 – 54.7 per cent). An ROE of 10.15 per cent (2023 – 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 6, 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 www.sedarplus.ca.

NMGC

As at December 31, 2023, NMGC serves approximately 540,000 customers with $1.8 billion USD in assets and 725 employees. NMGC’s system includes 2,408 km of transmission lines and 17,657 km of distribution lines. Annual natural gas throughput was 1 billion therms in 2023.

NMGC is subject to regulation by the NMPRC. Rates are set 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 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 6, 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 www.sedarplus.ca.

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 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.

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 RENAC’s payment obligations under the firm service agreement.

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 $158 million USD in 2023 (2022 – $170 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 2023 were $495 million USD (2022 - $436 million USD). In 2024, capital investment is expected to be approximately $465 million USD, including AFUDC. PGS and NMGC will make investments to maintain the reliability of their systems and support customer growth.

Environmental Considerations

PGS’s operations are subject to federal, state and local statutes, rules and regulations relating to the discharge of materials into the environment and the protection of the environment that generally require monitoring, permitting and ongoing expenditures. Previously, TEC had been a potentially responsible party (“PRP”) for certain superfund sites through its Tampa Electric and former PGS divisions, as well as for certain former manufactured gas plant sites through its PGS division. As a result of the separation of the PGS division into a separate legal entity, Peoples Gas System, Inc. is also now a PRP for those sites (in addition to third party PRPs for certain sites). For further details, refer to Note 27, Commitments and Contingencies – Legal Proceedings - Superfund and Former Manufactured Gas Plant Sites, 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 www.sedarplus.ca.

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.

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 equity investment in Lucelec on the island of St. Lucia.

Market and Sales

Other Electric Utilities operating revenues for 2023 were $390 million USD (2022 – $398 million USD) and electric sales volumes were 1,260 GWh (2022 –1,239 GWh).

BLPC

As at December 31, 2023, BLPC serves approximately 134,000 customers with $517 million USD of assets and a workforce of 414 employees. BLPC owns 243 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 3,839 km of distribution lines which includes distribution supply substations.

BLPC currently operates pursuant to a single integrated license to generate, transmit and distribute electricity on the island of Barbados until 2028. In 2019, the Government of Barbados passed legislation requiring multiple licenses for the supply of electricity. In 2021, BLPC reached commercial agreement with the Government of Barbados for each of the license types, subject to the passage of implementing legislation.The timing of the final enactment is unknown at this time, but BLPC will work towards the implementation of the licenses once enacted.

BLPC is regulated by the FTC. 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 is 10 per cent.

GBPC

As at December 31, 2023, GBPC serves approximately 19,000 customers, with $334 million USD of assets and a workforce of 205 employees. GBPC owns 98 MW of oil-fired generation, approximately 90 kilometres of transmission facilities and 994 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. GBPC’s approved regulatory return on rate base is 8.52 per cent for 2024 (2023 – 8.32 per cent). For further details on GBPC’s regulatory environment and recovery mechanisms, refer to Note 6, 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 www.sedarplus.ca.

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 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 $28 million USD in 2023 (2022 – a loss of $35 million USD). Other Electric Utilities’ contribution to consolidated adjusted net income was $26 million USD in 2023 (2022 – $23 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 www.sedarplus.ca.

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 2023 were $47 million USD (2022 – $48 million USD). In 2024, capital investment is expected to be approximately $80 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 Block Energy. 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. Block Energy 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 U.S. It also includes costs associated with corporate activities that are not directly allocated to the operations of Emera’s subsidiaries and investments.

Emera Energy

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

Contribution to Consolidated Net Income and Adjusted Net Income

Other’s contribution to consolidated net income was a loss of $147 million in 2023 (2022 – loss of $39 million). Other’s contribution to consolidated adjusted net income was a loss of $314 million in 2023 (2022 – loss of $218 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 www.sedarplus.ca.

Capital Investment

In 2024, capital investment in the Other segment is not expected to be significant.

GENERAL DEVELOPMENT OF THE BUSINESS

Three Year History and Changes Expected in 2024

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 Rates

On August 6, 2021, TEC filed with the FPSC a joint motion for approval of a settlement agreement by TEC 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 TEC. 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 Big Bend Modernization project and solar generation. The allowed equity in the capital structure will continue to be 54 per cent from investor sources of capital. The settlement agreement includes an allowed regulated ROE range of 9.0 per cent to 11.0 per cent with a 9.95 per cent midpoint.

On August 16, 2022, the FPSC approved TEC’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.

On August 16, 2023, TEC filed a petition to implement the 2024 Generation Base Rate Adjustment provisions pursuant to the 2021 rate case settlement agreement. Inclusive of TEC’s ROE adjustment, the increase of $22 million USD was approved by the FPSC on November 17, 2023.

On February 1, 2024, TEC notified the FPSC of its intent to seek a base rate increase effective January 2025, reflecting a revenue requirement increase of approximately $290 to $320 million USD and additional adjustments of approximately $100 million USD and $70 million USD for 2026 and 2027, respectively. TEC’s proposed rates include recovery of solar generation projects, energy storage capacity, a more resilient and modernized energy control center, and numerous other resiliency and reliability projects. The filing range amounts are estimates until TEC files its detailed case in April 2024. The FPSC is scheduled to hear the case in Q3 2024 with a decision expected by the end of 2024.

Fuel Recovery

The mid-course fuel adjustment requested by TEC on July 19, 2021, was approved on August 3, 2021. The rate increase, effective with September 2021 customer bills, covered higher fuel and capacity costs of $83 million USD, and was spread over customer bills from September through December 2021.

The mid-course fuel adjustment requested by TEC 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.

On January 23, 2023, TEC 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 changes were approved by the FPSC on March 7, 2023, and were effective beginning on April 1, 2023.

Solar Projects

During 2017 to 2021, TEC 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 Modernization Project

TEC 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, TEC retired the Unit 1 components that will not be used in the modernized plant in 2020 and Big Bend Unit 2 in 2021. TEC retired Big Bend Unit 3 in 2023 as it is in the best interest of the customers from an economic, environmental risk and operational perspective. On December 31, 2021, the remaining costs of the retired Big Bend coal generation assets, Units 1 through 3, of $636 million USD and $267 million USD in accumulated depreciation were reclassified to a regulatory asset on the balance sheet.

TEC’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 were recovered as part of the 2023 subsequent year adjustment. The settlement agreement also includes a new charge to recover the remaining costs of the retired Big Bend coal generation assets, Units 1 through 3, which are spread over 15 years, effective January 1, 2022. This recovery mechanism is authorized by and survives the term of the settlement agreement approved by the FPSC in 2021.

Storm Reserve

In September 2022, TEC was impacted by Hurricane Ian with $119 million USD of restoration costs charged against TEC’s FPSC approved storm reserve. Total restoration costs charged to the storm reserve exceeded the reserve balance and have been deferred as a regulatory asset for future recovery.

On January 23, 2023, TEC petitioned the FPSC for recovery of the storm reserve regulatory asset and the replenishment of the balance in the storm reserve to the approved storm reserve level of $56 million USD, for a total of $131 million USD. The storm cost recovery surcharge was approved by the FPSC on March 7, 2023, and TEC began applying the surcharge in April 2023. Subsequently, on November 9, 2023, the

FPSC approved TEC’s petition, filed on August 16, 2023, to update the total storm cost collection to $134 million USD. It also changed the collection of the expected remaining balance of $29 million USD as of December 31, 2023, from over the first three months of 2024 to over the 12 months of 2024. The storm recovery is subject to review of the underlying costs for prudency and accuracy by the FPSC.

In Q3 2023, TEC was impacted by Hurricane Idalia. The related storm restoration costs were approximately $35 million USD, which were charged to the storm reserve regulatory asset, resulting in minimal impact to earnings. TEC will determine the timing of the request for recovery of Hurricane Idalia costs at a future time.

Storm Protection Cost Recovery Clause and Settlement Agreement

The Storm Protection Plan (“SPP”) Cost Recovery Clause provides a process for Florida investor-owned utilities, including TEC, 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 TEC’s cost recovery began in January 2021. The previously approved plan addressed the years 2020 through 2022, and in April 2022 TEC submitted a new plan to determine cost recovery in 2023, 2024 and 2025. On October 4, 2022, the FPSC approved TEC’s current SPP for those years.

For more information, refer to the “Regulatory Environments and Updates – Florida Electric Utility” section of Note 6, 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 www.sedarplus.ca

Canadian Electric Utilities

NSPI

General Rate Application

On February 2, 2023, the UARB approved the General Rate Application Settlement Agreement between NSPI, key customer representatives and participating interest groups. This resulted in average customer rate increases of 6.9 per cent effective on February 2, 2023, and further average increase of 6.5 per cent on January 1, 2024, with any under or over-recovery of fuel costs addressed through the UARB’s established FAM process. It also established a storm rider and a demand-side management rider. On March 27, 2023 the UARB issued a final order approving the electricity rates effective on February 2, 2023.

Fuel Recovery

For the period of 2020 through 2022, NSPI operated under a three-year fuel stability plan with no fuel rate adjustments related to the under-recovery of fuel and fuel-related costs in the period.

On January 29, 2024, NSPI applied to the UARB for approval of a structure that would begin to recover the outstanding FAM balance. As part of the application, NSPI requested approval for the sale of $117 million of the FAM regulatory asset to Invest Nova Scotia, a provincial Crown corporation, with the proceeds paid to NSPI upon approval. NSPI has requested approval to collect from customers the amortization and financing costs of $117 million on behalf of Invest Nova Scotia over a 10-year period, and remit those amounts to Invest Nova Scotia as collected, reducing short-term customer rate increases relative to the currently established FAM process. If approved, this portion of the FAM regulatory asset would be removed from the Consolidated Balance Sheets and NSPI would collect the balance on behalf of Invest Nova Scotia in NSPI rates beginning in 2024. A decision is expected in the first half of 2024. It is anticipated that NSPI will apply to the UARB later in 2024 to collect additional under-recovered fuel amounts in 2025 or future periods, subject to the approval of the UARB.

Extra Large Industrial Active Demand Tariff

On July 5, 2023, NSPI received approval from the UARB to change the methodology in which fuel cost recovery from an industrial customer is calculated. Due to significant volatility in commodity prices in 2022, the previous methodology did not result in a reasonable determination of the fuel cost to serve this customer. The change in methodology, effective January 1, 2022, results in a shifting of fuel costs from this industrial customer to the FAM. This adjustment was recorded in Q2 2023 resulting in a $51 million increase to the FAM regulatory asset and an offsetting decrease to unbilled revenue within Receivables and other current assets. This adjustment had minimal impact on earnings.

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 km per hour and peak gusts of approximately 180 km 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 $120 million, of which $96 million was capitalized to “PP&E” and $24 million deferred to “Other long-term assets” for future amortization, subject to UARB approval.

On October 31, 2023, NSPI submitted an application to the UARB to defer $24 million in incremental operating costs incurred during Hurricane Fiona storm restoration efforts in September 2022. NSPI is seeking amortization of the costs over a period to be approved by the UARB during a future rate setting process. At December 31, 2023 the $24 million is deferred to “Other long-term assets”, pending UARB approval.

Post-Tropical Storm Lee

On September 16, 2023, Nova Scotia was struck by post-tropical storm Lee and as a result, approximately 280,000 customers lost power. The total cost of storm restoration was $19 million, with $9 million charged to OM&G, $5 million capitalized to PP&E and $5 million deferred to the UARB approved storm rider. The storm rider for each of 2023, 2024, and 2025 allows NSPI to apply to the UARB for deferral and recovery of expenses if major storm restoration expenses exceed approximately $10 million in any given year. The application for deferral of the storm rider is made in the year following the year of the incurred costs, with recovery beginning in the year after the application.

Regulatory Matters – General

For more information, refer to the “Regulatory Environments and Updates – Canadian Electric Utilities – NSPI” section of Note 6, 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 www.sedarplus.ca.

Environmental Legislation and Regulations

Greenhouse Gas Emissions

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.

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.

Clean Electricity Solutions Task Force

The Clean Electricity Solutions Task Force (the “Task Force”) was created by the Province in April 2023 to advise the provincial government on Nova Scotia’s transition away from coal to more renewable sources of energy. On February 23, 2024, the Task Force released its report and recommendations, based on engagement with stakeholders, including NSPI. The Task Force report focuses on findings related to system operations, regulatory oversight, reliability, transmission and affordability. The Task Force announced a number of recommendations including a strengthening of the authority and independence of the regulator and the establishment of an independent system operator in order to support the continuing transition to clean energy and the achievement of federal and provincial clean energy goals and legislation. The Province announced they intend to accept these recommendations and will table enabling legislation in its upcoming session which starts February 27, 2024.

Nova Scotia Renewable Electricity Regulations

Under the provincially legislated RER , starting in 2020, 40 per cent of electric sales must be generated from renewable sources. NSPI met this target in 2023, with 43 per cent of NSPI’s electric sales coming form renewable sources, subject to a compliance filing.

Due to the delay of NSPI receiving energy form the NS Block, the Province provided NSPI with an alternative compliance plan that required 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.

On April 6, 2023, the Province levied a $10 million penalty on NSPI for non-compliance with the RER compliance period ending in 2022. The penalty was recorded in OM&G on the Consolidated Statements of Income. On May 26, 2023, NSPI initiated an appeal of the penalty through a proceeding with the UARB, as permitted under the RER. On October 12, 2023, the UARB decided that it will hear the appeal by giving due deference to the Province’s decision but permitting the filing of new evidence to support the parties’ positions. The hearing for the matter is scheduled for June 2024 and a decision is expected before the end of 2024.

Carbon Pricing Regulations

In November 2022, the Province enacted amendments to the Environment Act which provided the framework for Nova Scotia to implement an OBPS to comply with the Government of Canada’s 2023 through 2030 carbon pollution pricing regulations effective January 1, 2023. The Government of Canada approved the Province’s proposed system, however the OBPS will be subject to an interim review by the Government of Canada of the standards effective for 2026. The final Output-Based Pricing System

Reporting and Compliance Regulations were prescribed by Order in Council dated January 30, 2024. The OBPS GHG emissions performance standards for large industrial GHG emitters that vary by fuel type. GHG emissions in excess of the prescribed intensity standards will be subject to a carbon price that starts at $65 per tonne in 2023 and will 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 Cap-and-Trade Program Regulations

NSPI was a participant in the Nova Scotia Cap-and-Trade Program and was subject to the 2019 through 2022 compliance period. On March 16, 2023, the Province provided NSPI with emissions allowances sufficient to achieve compliance for the 2019 through 2022 compliance period. As such, compliance costs accrued of $166 million were reversed in Q1 2023. The credits NSPI purchased from provincial auctions in the amount of $6 million were not refunded and no further costs were incurred to achieve compliance with the Nova Scotia Cap-and-Trade Program.

Other Legislation

Electricity Act Amendment

On November 9, 2023, the Province enacted amendments in the Electricity Act which permit the Governor in Council to approve energy storage projects proposed by a public utility and owned wholly or in majority by the public utility if the project is in the best interest of ratepayers. Further, the amendments to the Electricity Act expand the ability of the Province to require NSPI to enter into power purchase agreements with renewable generation facilities by further empowering the Province to require NSPI to enter into an agreement for the sale of the electricity to specified customers. This allows specified customers to buy renewable electricity from specified producers, with NSPI managing the transmission and sale of the energy. On December 21, 2023, the Governor in Council enacted regulations which directed NSPI to install three 50 MW four-hour duration grid-scale batteries as part of the regulated assets of NSPI.

Performance Standards Penalty Amendment

On April 12, 2023, the Province enacted amendments to the Public Utilities Act which increased the cumulative total of administrative penalties that could be levied by the UARB against NSPI for non-compliance with current and future performance standards in a calendar year from $1 million to $25 million. Any administrative penalties levied against NSPI must be credited to customers and NSPI cannot recover administrative penalties imposed through rates.

ENL

Maritime Link Project

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, subject to a monthly holdback of up to $2 million, which will increase to $4 million beginning December 2023, as discussed below.

On October 4, 2023 and January 31, 2024, the UARB issued decisions providing clarification on remaining aspects of the Maritime Link holdback mechanism primarily relating to release of past and future holdback amounts and requirements to end the holdback mechanism. In these decisions, the UARB agreed with the Company’s submission that $12 million ($8 million related to 2022 and $4 million relating to 2023) of the previously recorded holdback remain credited to NSPI’s FAM, with the remainder released to NSPML and recorded in Emera’s “Income from equity investments”. NSPML did not record any additional holdback in Q4 2023. The UARB also confirmed that the holdback mechanism will cease once 90 per cent of NS Block deliveries are achieved for 12 consecutive months (subject to potential relief for planned outages or exceptional circumstances) and the net outstanding balance of previously underdelivered NS Block energy is less than 10 per cent of the contracted annual amount. In addition, the UARB increased the monthly holdback amount from $2 million to $4 million beginning December 1, 2023. NSPML expects to file an application to terminate the holdback in 2024.

On December 21, 2023, NSPML received approval to collect up to $164 million from NSPI for the recovery of costs associated with the Maritime Link in 2024; subject to a holdback of up to $4 million a month, as discussed above.

Gas Utilities and Infrastructure

PGS

Base Rates

On November 19, 2020, the FPSC approved a settlement agreement filed by PGS. The settlement agreement allowed 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 provided PGS the ability to reverse a total of $34 million USD of accumulated depreciation through 2023. PGS reversed $20 million USD of accumulated depreciation in 2023 and $14 million USD in 2022.

On April 4, 2023, PGS filed a rate case with the FPSC and a hearing for the matter was held in September 2023. On November 9, 2023, the FPSC approved a $118 million USD increase to base revenues which includes $11 million USD transferred from the cast iron and bare steel replacement rider, for a net incremental increase to base revenues of $107 million USD. This reflects a 10.15 per cent midpoint ROE with an allowed equity capital structure of 54.7 per cent. A final order was issued on December 27, 2023, with the new rates effective January 2024.

NMGC

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.

On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates to become effective Q4 2024. NMGC requested $49 million USD in annual base revenues primarily as a result of increased operating costs and capital investments in pipeline projects and related infrastructure. The rate case includes a requested ROE of 10.5 per cent. A final order from the NMPRC is expected in Q3 2024.

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 from July 1, 2021, to December 31, 2023.

For more information, refer to the “Regulatory Environments and Updates – Gas Utilities and Infrastructure” section of Note 6, 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 www.sedarplus.ca.

Other Electric Utilities

BLPC

General Rate Review

In 2021 BLPC submitted a general rate review application to the FTC. In September 2022, the FTC granted BLPC interim rate relief, allowing an increase in base rates of approximately $1 million USD per month. On February 15, 2023, the FTC issued a decision on the 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 related to the self-insurance fund of $50 million USD, prior year benefits recognized on remeasurement of deferred income taxes of $5 million USD, and accumulated depreciation of $16 million USD. On March 7, 2023, BLPC filed a Motion for Review and Variation (the “Motion”) and applied for a stay of the FTC’s decision, which was subsequently granted. On November 20, 2023, the FTC issued their decision dismissing the Motion. Interim rates continue to be in effect through to a date to be determined in a final decision and order.

On December 1, 2023, BLPC appealed certain aspects of the FTC’s February 15 and November 20, 2023, decisions to the Supreme Court of Barbados in the High Court of Justice (the “Court”) and requested that they be stayed. On December 11, 2023, the Court granted the stay. BLPC’s position is that the FTC made errors of law and jurisdiction in their decisions and believes the success of the appeal is probable, and as a result, the adjustments to BLPC’s final rates and rate base, including any adjustments to regulatory assets and liabilities, have not been recorded at this time. Management does not expect the final decision and order to have a material impact on adjusted net income.

Clean Energy Transition Program (“CETP”)

On May 31, 2023, the FTC approved BLPC’s application to establish an alternative cost recovery mechanism to recover prudently incurred costs associated with its CETP (the “Decision”). The mechanism is intended to facilitate the timely recovery between rate cases of costs associated with approved renewable energy assets. BLPC will be required to submit an individual application for the recovery of costs of each asset through the cost recovery mechanism, meeting the minimum criteria as set out in the Decision. On October 5, 2023, BLPC applied to the FTC to recover the costs of a battery storage system through the CETP.

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 rates include a regulatory ROE of 12.84 per cent.

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 was adjusted monthly, in-line with actual fuel costs.

Storm Restoration Costs – Hurricane Matthew

As part of the recovery of costs incurred as a result of Hurricane Matthew in 2016, 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.

For more information, refer to the “Regulatory Environments and Updates – Other Electric Utilities” section of Note 6, 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 www.sedarplus.ca.

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

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.

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, which expired on September 5, 2023.

On November 14, 2023, 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 dated November 14, 2023 to the Company’s short form base shelf prospectus dated October 3, 2023. The ATM program is expected to remain in effect until November 4, 2025.

During 2023, approximately 8.29 million common shares were issued under the ATM Program at an average price of $48.27 per share for gross proceeds of $400 million ($397 million net of after-tax issuance costs) and an aggregate gross sales limit of $200 million remained available for issuance under the ATM Program.

During 2024, up to and including February 26, 2024, no common shares were issued under the ATM Program and an aggregate gross sales limit of $200 million remains available for issuance under the ATM Program.

Preferred Share Issuances

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.

On July 6, 2023, Emera announced it would not redeem the 10 million outstanding Series C First Preferred Shares. The holders of the Series C First Preferred Shares had the right, at their option, to convert all or any of their Series C First Preferred Shares, on a one-for-one basis, into Series D First Preferred Shares on August 15, 2023 or to continue to hold their Series C First Preferred Shares. On August 4, 2023, Emera announced after having taken into account all conversion notices received from holders, no Series C First Preferred Shares would be converted into Series D First Preferred Shares.

On July 6, 2023, Emera announced it would not redeem the 12 million outstanding Series H First Preferred Shares. The holders of the Series H First Preferred Shares had the right, at their option, to convert all or any of their Series H First Preferred Shares, on a one-for-one basis, into Series I First Preferred Shares on August 15, 2023 or to continue to hold their Series H First Preferred Shares. On August 4, 2023, Emera

announced after having taken into account all conversion notices received from holders, no Series H First Preferred Shares would be converted into Series I First Preferred Shares.

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.

On May 2, 2023, Emera issued $500 million in senior unsecured notes that bear interest at 4.84 per cent with a maturity date of May 2, 2030. The proceeds were used to repay Emera’s $500 million unsecured fixed rate notes, which matured in June 2023.

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

RISK FACTORS

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

CAPITAL STRUCTURE

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

As at December 31, 2023, 284,117,511 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, 2023, 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, 2023, Emera had not issued any second preferred shares.

Share Ownership Restrictions

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

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

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

CREDIT RATINGS

Emera has the following credit ratings by the Rating Agencies:

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 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, 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 www.sedarplus.ca.

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 20, 2023 Emera extended its annual dividend growth rate target of four to five per cent through 2026. 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 2023.

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

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 2023 are set out In Appendix “C” of this AIF.

At-The-Market Equity Program

On November 14, 2023, 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 dated November 14, 2023 to the Company’s short form base shelf prospectus dated October 3, 2023. The ATM program is expected to remain in effect until November 4, 2025, unless terminated prior to such date by the Company or otherwise in accordance with the terms of the equity distribution agreement. As at December 31, 2023, an aggregate gross sales limit of approximately $200 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, 2023⁽¹⁾:

Officers

The Officers of Emera as at December 31, 2023 were as follows:

As at December 31, 2023, the Directors and Officers, in total, beneficially owned or controlled, directly or indirectly, 184,256 common shares or less than 1 per cent of the issued and outstanding common shares of Emera.

AUDIT COMMITTEE

The Audit Committee of Emera is composed of the following five members, all of whom are independent Directors: Kent M. Harvey (Chair), Paula Gold-Williams, B. Lynn Loewen, Ian E. Robertsonand Andrea S. Rosen. 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 before he retired in 2016, 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, 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. Co-Chair of the Keystone Policy Center, having been a member of both the Policy Center and its Energy Board since 2016. Former Board member and Treasurer of EPIcenter, an innovation think tank; incubator and accelerator; and strategic advisory organization. She also serves on the US Secretary of Energy’s Advisory Board (“SEAB”) and is a member of the board of directors of ReNew Energy Global Plc, a renewable energy company based in India. 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 Canadian supplier of innovative medical technologies, supplies and equipment. From 2008 to 2011, she was President of Expertech Network Installation Inc., a Canadian network infrastructure service provider and also held key positions with Bell Canada Enterprises, as Vice President of Finance Operations and Vice President of Financial Controls. Earlier in her career, she was with Air Canada Jazz where she held positions of increasing responsibility, including Vice President of Corporate Services and Chief Financial Officer. She is a member of the Board of Directors of National Bank of Canada, a Canadian Chartered Bank, Chair of its Audit Committee and member of its Technology Comittee. She was a member of the Board of Directors of Xplore Inc., a Canadian broadband service provider, and a member of its Audit Committee from 2021 to 2023. She is also a former member of the Public Sector Pension Investment Board where she served on the Audit and Conflicts Committee and as Audit Committee Chair. Chancellor of Mount Allison University and a member of the Executive Committee and Chair of its Nominating and Governance Committee since 2018. She was a member of the Board of Regents from 1998 to 2008, serving as Chair from 2007-2008. 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.

Ian E. Robertson

A principal of the Northern Genesis Capital Group, an investment group 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. Former Member of the Board of Directors of Northern Genesis Acquisition Corp., Northern Genesis Acquisition Corp. II and Northern Genesis Acquisition Corp. III and a former Director of Embark Technology, Inc., an autonomous vehicle company,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. 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. Prior to this, 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 (“AIMCo.”). Former member of the Board of Directors of the Institute of Corporate Directors.

Audit and Non-Audit Services Pre-Approval Process

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

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

Auditors’ Fees

The aggregate fees billed by Ernst & Young LLP, the Company’s external auditors, during the fiscal years ended December 31, 2023 and 2022 respectively, were as follows:

CERTAIN PROCEEDINGS

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

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, 2023, nor has it entered into any material contracts outside the ordinary course of business prior to the year ended December 31, 2023 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 www.sedarplus.ca or upon request to the Corporate Secretary, Emera Incorporated, P.O. Box 910, Halifax, N.S., B3J 2W5, telephone (902) 428-6096 or fax (902) 428-6171. Additional information, including Directors’ and Officers’ remuneration and indebtedness, principal holders of Emera’s securities and securities authorized for issuance under equity compensation plans, is contained in Emera’s information circular for the most recent annual meeting of Emera’s common shareholders. Additional financial information is provided in Emera’s Audited Financial Statements and MD&A.

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

APPENDIX “A” - Definitions of Certain Terms

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

As of December 31, 2023, 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.

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:

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, 2023, 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.

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.

APPENDIX “C” - MONTHLY TRADING VOLUME AND HIGH AND LOW PRICE FOR EMERA’S SECURITIES IN 2023

February 2023

APPENDIX “D” - EMERA INCORPORATED AUDIT COMMITTEE CHARTER

PART I

MANDATE AND RESPONSIBILITIES

Committee Purpose

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

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

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.

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

The Committee shall oversee:

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:

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.

The Committee shall:

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

PART III

COMMITTEE PROCEDURE

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.

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.

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.

The Committee shall:

The Committee shall:

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.