Emera (EMRAF) 40-F2021 FY Annual report (Canada)

Exhibit 99.1

Emera Incorporated

Annual Information Form

For the year ended December 31, 2021

February 14, 2022

ANNUAL INFORMATION FORM

For the year ended December 31, 2021

Dated: February 14, 2022

TABLE OF CONTENTS

PRESENTATION OF INFORMATION

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

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

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

CAUTIONARY NOTE 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 risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; liquidity and capital market risk; future dividend growth; timing and costs associated with certain capital investments; the expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; maintenance of adequate insurance coverage; changes in customer energy usage patterns; developments in technology that could reduce demand for electricity; global climate change; weather; unanticipated maintenance and other expenditures; system operating and maintenance risk; derivative financial instruments and hedging; interest rate risk; counterparty risk; disruption of fuel supply; country risks; environmental risks; foreign exchange; regulatory and government decisions, including changes to environmental, financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of service area; risk of failure of information technology infrastructure and cybersecurity risks; uncertainties associated with infectious diseases, pandemics and similar public health threats, such as the COVID-19 novel coronavirus (“COVID-19”) pandemic; market energy sales prices; labour relations; and availability of labour and management resources.

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

CORPORATE STRUCTURE

Name and Incorporation

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

Amended Articles of Association

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

Intercorporate Relationships

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

INTRODUCTION

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

Emera’s investment in rate-regulated businesses is concentrated in Florida and Nova Scotia. These service areas have generally experienced stable regulatory policies and economic conditions. Emera’s portfolio of regulated utilities provides reliable earnings, cash flow and dividends. Earnings opportunities in regulated utilities are generally driven by the magnitude of net investment in the utility (known as “rate base”), and the amount of equity in the capital structure and the ROE as approved through regulation. Earnings are also affected by sales volumes and operating expenses.

Emera’s capital investment plan is $8.4 billion over the 2022-to-2024 period (including a $240 million equity investment in the LIL in 2022), with an additional $1 billion of potential capital investments over the same period. This results in a forecasted rate base growth of approximately 7 per cent to 8 per cent through 2024. The capital investment plan continues to include significant investments across the portfolio in renewable and cleaner generation, reliability and integrity investments, infrastructure modernization and customer-focused technologies. Emera’s capital investment plan is being funded primarily through internally generated cash flows and debt raised at the operating company level. Equity requirements in support of the Company’s capital investment plan are expected to be funded through the issuance of preferred equity and the issuance of common equity through Emera’s dividend reinvestment plan and ATM Program. Maintaining investment-grade credit ratings is a priority of management.

Emera has provided annual dividend growth guidance of four to five per cent through 2024. The Company targets a long-term dividend payout ratio of adjusted net income of 70 to 75 per cent and, while the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to return to that range over time. For further information on the non-GAAP measure “Dividend Payout Ratio of Adjusted Net Income”, refer to the “Non-GAAP Financial Measures” section of the MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

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

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

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

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

Building on its decarbonization progress over the past 15 years, Emera is continuing its efforts by establishing clear carbon reduction goals and a vision to achieve net-zero carbon dioxide emissions by 2050.

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

Emera seeks to deliver on its Climate Commitment while maintaining its focus on investing in reliability and never losing sight of affordability for customers. Emera is also committed to identifying emerging technologies and continuing to work constructively with policymakers, regulators, partners, investors and customers to achieve these goals and realize its net-zero vision.

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

COVID-19 Pandemic

The Company’s priorities continue to be the reliable delivery of essential energy services to meet customers’ demands while maintaining the health and safety of its customers and employees and supporting the communities in which Emera operates.

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

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

The Company currently expects to continue to have adequate liquidity given its cash position, existing bank facilities, and access to capital, but will continue to monitor the impact of COVID-19 on future cash flows. For further detail, refer to the “Liquidity and Capital Resources” section of the MD&A and for affiliate specific impacts of COVID-19, if applicable, refer to the outlook sections of the MD&A, by segment, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

DESCRIPTION OF THE BUSINESS

Business Segments

Emera’s reportable segments are:

General

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

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

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 Tampa Electric, a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity, serving customers in West Central Florida. Tampa Electric has $10.7 billion USD of assets, approximately 810,600 customers and 2,468 employees as at December 31, 2021.

Tampa Electric is regulated by the FPSC and is also subject to regulation by the FERC. The FPSC sets rates at a level that allows utilities such as Tampa Electric to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC rate setting hearings which occur at the initiative of Tampa Electric, the FPSC or other interested parties.

Market and Sales

Energy sources and generation

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

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

System Operations

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

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

Fuel Recovery Clause

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

Storm Protection Plan Cost Recovery Clause

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

Other Cost Recovery Clauses

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

Capital Cost Recovery for Early Retired Assets

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

Storm Reserve

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

Contribution to Consolidated Net Income

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

Seasonal Nature

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

Capital Investments

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

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

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

Environmental Considerations

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

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

Hazardous Air Pollutants

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

Carbon Reductions and GHG

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

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

Ozone

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

Water Supply and Quality

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

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

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

Canadian Electric Utilities

Canadian Electric Utilities includes NSPI and ENL. NSPI is a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity and the primary electricity supplier to customers in Nova Scotia. ENL is a holding company with a 100 per cent equity investment in NSPML and a 37.4 per cent equity investment in LIL: two transmission investments related to the development of an 824 MW hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador.

NSPI

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

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

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

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

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

Market and Sales

Energy Sources and Generation

NSPI owns 2,420 MW of generating capacity, of which approximately 44 per cent is coal-fired, 28 per cent is natural gas and/or oil, 19 per cent is hydro and wind, 7 per cent is petroleum coke and 2 per cent is biomass-fueled generation, supplemented by 546 MW contracted with IPPs, including COMFIT participants.

System Operations

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

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

Transmission and Distribution

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

ENL

NSPML

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

The Maritime Link assets entered service on January 15, 2018 enabling the transmission of energy between Newfoundland and Nova Scotia, improved reliability and ancillary benefits, supporting the efficiency and reliability of energy in both provinces. Nalcor continues to advance towards completion of the LIL with Nalcor forecasting it will achieve final commissioning in the first half of 2022. Nalcor’s NS Block delivery obligations commenced on August 15, 2021 and the NS Block will be delivered over the next 35 years pursuant to the project agreements. As Nalcor is in the final stages of commissioning the LIL, there will be commissioning related interruptions in supply with any resultant delivery shortfalls being delivered at a date to be agreed to by the companies.

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

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

LIL

ENL is a limited partner with Nalcor in LIL. Construction of the LIL is complete and Nalcor is forecasting it will achieve final commissioning in the first half of 2022.

Equity earnings from the LIL investment are based upon the book value of the equity investment and the approved ROE. Emera’s current equity investment is $682 million, comprised of $410 million in equity contribution and $272 million of accumulated equity earnings. Emera’s total equity contribution in the LIL, excluding accumulated equity earnings, is estimated to be approximately $650 million after all Lower Churchill projects are completed.

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

Contribution to Consolidated Net Income

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

Seasonal Nature

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

Capital Investment

NSPI

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

NSPML

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

Environmental Considerations

NSPI is subject to environmental laws and regulations set by both the Government of Canada and the Province of Nova Scotia. NSPI continues to work with both levels of government to comply with these laws and regulations, to maximize efficiency of emission control measures and minimize customer cost. NSPI anticipates that costs prudently incurred to achieve legislated reductions will be recoverable under NSPI’s regulatory framework.

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

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

Renewable Energy from Maritime Link Project

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

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

Other Environmental Legislation and Regulations

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

Other Electric Utilities

Other Electric Utilities includes ECI, a holding company with regulated electric utilities. ECI’s regulated utilities include vertically integrated regulated electric utilities of BLPC on the island of Barbados, GBPC on Grand Bahama Island, a 51.9 per cent interest in Domlec on the island of Dominica and a 19.5 per cent interest in Lucelec on the island of St. Lucia which is accounted for on the equity basis.

On March 24, 2020, Emera completed the sale of Emera Maine. For further detail, refer to the “Significant Items Affecting Earnings” sections of Emera’s MD&A, incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.emera.com.

Market and Sales

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

BLPC

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

BLPC currently operates pursuant to a franchise to generate, transmit and distribute electricity on the island of Barbados until 2028. In 2019, the Government of Barbados passed legislation amending the number of licenses required for the supply of electricity from a single integrated license which currently exists, to multiple licenses for Generation, Transmission and Distribution, Storage, Dispatch and Sales. In March 2021, BLPC reached commercial agreement with the Government of Barbados for each of the license types, subject to the passage of implementing legislation. For more details regarding the new licenses, please refer to the General Development of the Business section below, under the heading “BLPC License Negotiations”.

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

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

GBPC

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

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

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

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

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

Domlec

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

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

System Operation

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

Transmission and Distribution

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

Contribution to Consolidated Net Income and Adjusted Net Income

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

Seasonal Nature

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

Capital Investment

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

Environmental Considerations

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

Gas Utilities and Infrastructure

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

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

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

Market and sales

PGS

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

As of 2021, the approved ROE range for PGS was is 8.9 per cent to 11.0 per cent, based on an allowed equity capital structure of 54.7 per cent. An ROE of 9.9 per cent is used for the calculation of return on investments recovered through cost recovery clauses.

Fuel Recovery Clause

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

Other Cost Recovery Clauses

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

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

NMGC

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

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

Fuel Recovery Clause

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

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

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 for gas costs above what NMGC would normally have paid during this period. On June 15, 2021, the NMPRC approved the recovery over a period of 30 months beginning July 1, 2021. For more information, refer to the “Business Overview and Outlook – Gas Utilities and Infrastructure” section of Emera’s MD&A, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

Weather Normalization Mechanism

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

IMP Regulatory Asset

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

SeaCoast

In 2018, SeaCoast executed an agreement with Seminole Electric Cooperative, Inc. (“Seminole”) to provide long-term firm gas transportation service to Seminole’s new gas-fired generating facility being constructed in Putnam County, Florida.

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

EBPC

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

Since its commissioning in July 2009, the pipeline has been used solely to transport natural gas for RECL under a 25-year firm service agreement, which expires in 2034. Brunswick Pipeline is regulated by the CER, which has classified it as a Group II pipeline. As a regulated Group II pipeline, the tolls of Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to a regulatory approval process. In the absence of a complaint, the CER does not normally undertake a detailed examination of Brunswick Pipeline’s tolls, which are subject to a firm service agreement with RECL, as noted above. The firm service agreement provides for a predetermined toll increase in the fifth and fifteenth year of the contract.

M&NP

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

Contribution to Consolidated Net Income

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

Seasonal Nature

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

Capital Investment

Capital investments (including AFUDC) in the Gas Utilities and Infrastructure segment in 2021 were $407 million USD (2020 - $553 million USD). In 2022, capital investment is expected to be approximately $445 million USD, including AFUDC. PGS will make investments to expand its system and support customer growth. NMGC will continue to make investments to maintain the reliability of its system and support customer growth.

Environmental Considerations

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

Economic Dependence

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

Other

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

Business operations in the Other segment include Emera Energy and ETL. Emera Energy consists of EES, a wholly owned physical energy marketing and trading business and an equity investment in a 50.0 per cent joint venture ownership of Bear Swamp, a 633 MW pumped storage hydroelectric facility in northwestern Massachusetts. ETL is a wholly owned technology company focused on finding ways to deliver renewable and resilient energy to customers.

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

Emera Energy

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

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

Contribution to Consolidated Net Income and Adjusted Net Income

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

Capital Investment

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

GENERAL DEVELOPMENT OF THE BUSINESS

Three Year History and Changes Expected in 2022

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

COVID-19 Pandemic

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

Florida Electric Utility

Base Rate Adjustments – Approval of Settlement Agreement

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

Fuel and Capacity Charges

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

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

Solar Projects

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

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

Big Bend Power Station Modernization

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

Storm Protection Cost Recovery Clause

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

Canadian Electric Utilities

NSPI

Environmental Legislation and Regulations

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

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

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

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

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

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

General Rate Application

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

Regulatory Matters - General

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

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

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

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

Regulatory Matters – Maritime Link

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

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

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

ENL

Maritime Link Project

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

On August 9, 2021, NSPML filed a final capital cost application with the UARB seeking approval to recover capital costs associated with the Maritime Link and approval of NSPML’s 2022 assessment. In December 2021, NSPML obtained an interim decision from the UARB approving interim rates beginning January 1, 2022, until receipt of the UARB’s decision on the application. On February 9, 2022, the UARB issued its decision relating to the Maritime Link project, approving NSPML’s requested rate base of approximately $1.8 billion costs that would not otherwise have been recoverable if incurred by NSPI. For information on the UARB decision, refer to the “Description of the Business - ENL - NSPML” section above.

Delivery of NS Block

Nalcor’s NS Block delivery obligations commenced on August 15, 2021, and delivery will continue over the next 35 years pursuant to the project agreements. As Nalcor is in the final stages of commissioning the LIL, there will be commissioning related interruptions in supply with any resultant delivery shortfalls being delivered at a date to be agreed to by the companies. For further information on the NS Block, refer to the “Business Overview and Outlook – Canadian Electric Utilities” and “Contractual Obligations” sections of the MDA, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

Other Electric Utilities

Sale of Emera Maine

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

ECI

BLPC General Rate Review

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

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

BLPC License Negotiations

BLPC is regulated by the Fair Trading Commission (“FTC”), an independent regulator, under the Utilities Regulation (Procedural) Rules 2003. The Government of Barbados has granted BLPC a franchise to generate, transmit and distribute electricity on the island until 2028. In 2019, the Government of Barbados passed legislation amending the number of licenses required for the supply of electricity from a single integrated license which currently exists to multiple licenses for Generation, Transmission and Distribution, Storage, Dispatch and Sales. In March 2021, BLPC reached commercial agreement with the Government of Barbados for each of the license types, subject to the passage of implementing legislation. Following a general election called late in 2021 for January 19, 2022, the new licenses are expected to take effect in 2022 on completion of the legislative process. The Dispatch license will have a term of five years with the remaining licenses having terms ranging from 25-30 years. BLPC anticipates that any increased costs associated with the implementation of the new multi-licensed structure will be recoverable through BLPC’s regulatory framework. BLPC is currently assessing the full impact of the new licenses on its business and working towards the successful implementation of the licenses.

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

BLPC Fuel Hedging

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

GBPC Application for Rate Review

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

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

Gas Utilities and Infrastructure

PGS

Settlement Agreement

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

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

NMGC

Settlement Agreement

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

NMGC Winter Event Gas Cost Recovery

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

Rate Case

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

Other

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

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

Removal of Legislative Restriction on Non-Canadian Resident Ownership

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

USGAAP – Exemptive Relief and Companies Act Relief

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

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

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

Financing Activity

At-The-Market Equity Program

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

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

On August 12, 2021, Emera renewed its ATM Program that allows the Company to issue up to $600 million of common shares from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price. The ATM Program was renewed pursuant to a prospectus supplement to the Company’s short form base shelf prospectus dated August 5, 2021. The ATM program is expected to remain in effect until September 5, 2023.

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

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

Preferred Share Issuances

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

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

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

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

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

Senior Notes

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

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

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

RISK FACTORS

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

CAPITAL STRUCTURE

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

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

Common Shares

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

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

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

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

Emera First Preferred Shares

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

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

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

Emera Second Preferred Shares

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

Share Ownership Restrictions

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

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

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

CREDIT RATINGS

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

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.

DIVIDENDS

Any dividend payments will be at the Board’s discretion based upon earnings and capital requirements and any other factors as the Board may consider relevant. On September 24, 2021 Emera extended its annual dividend growth rate target of four to five per cent through 2024. The Company targets a long-term dividend payout ratio of 70 to 75 per cent, and while the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to return to that range over time.

Emera maintains the Dividend Reinvestment Plan, which provides an opportunity for shareholders to reinvest dividends and to participate in optional cash contributions for the purpose of purchasing common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2021.

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

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 2021 are set out In Appendix “C” of this AIF.

At-The-Market Equity Program

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

DIRECTORS AND OFFICERS

Directors

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

Officers

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

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

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

AUDIT COMMITTEE

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

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

Kent M. Harvey, Committee Chair

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

B. Lynn Loewen, FCPA, FCA

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

Andrea S. Rosen

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

Richard P. Sergel

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

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

Audit and Non-Audit Services Pre-Approval Process

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

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

Auditors’ Fees

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

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

CERTAIN PROCEEDINGS

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

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, 2021, nor has it entered into any material contracts outside the ordinary course of business prior to the year ended December 31, 2021 that are still in effect as at the date of this AIF.

TRANSFER AGENT AND REGISTRAR

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

EXPERTS

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

ADDITIONAL INFORMATION

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

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

APPENDIX “A” - Definitions of Certain Terms

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

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

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

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

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

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

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

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

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

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

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

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

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

Series 2016-A Conversion, First Preferred Shares

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

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

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 2021

February 2022

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.

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

Two 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.