Exhibit 99.1

Emera Incorporated

Annual Information Form

For the year ended December 31, 2020

March 29, 2021

ANNUAL INFORMATION FORM

For the year ended December 31, 2020

Dated: March 29, 2021

PRESENTATION OF INFORMATION

Unless otherwise noted, the information contained in this Annual Information Form (“AIF”) is given at or for the period ended December 31, 2020. 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, EBITDA and adjusted EBITDA as financial performance measures, which are not defined financial measures according to USGAAP and do not have standardized meanings prescribed by USGAAP. For further discussion of such terms, see the Company’s Management’s Discussion and Analysis dated February 16, 2021 for the year ended December 31, 2020 (“MD&A”).

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 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 investment; 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 investment 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, 2020.

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 gas and electric services in designated territories under franchises and are overseen by regulatory authorities. Emera’s strategic focus continues to be to safely deliver 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 return on that equity (“ROE”) as approved through regulation. Earnings are also affected by sales volumes and operating expenses.

Emera’s $7.4 billion capital investment plan over the 2021-to-2023 period, and the potential for additional capital opportunities of $1.2 billion over the same period, results in a forecasted rate base growth of 7.5 per cent to 8.5 per cent through to 2023. The capital investment plan continues to include significant investments across the portfolio in renewable and cleaner generation, 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 will predominantly be funded in equity capital markets through the dividend reinvestment plan and issuance of common and preferred equity. Maintaining investment-grade credit ratings is a priority of management.

Emera has provided annual dividend growth guidance of four to five per cent through to 2022. 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.

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 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 at Tampa Electric, and the modernization of the Big Bend Power Station at Tampa Electric. Emera’s utilities are also investing in reliability projects and replacing aging infrastructure. All of these projects demonstrate Emera’s strategy of safely delivering cleaner, reliable, and affordable energy for its customers.

Building on its decarbonization progress over the past 15 years, Emera is continuing its efforts by establishing clear carbon reduction goals and a vision to achieve net-zero carbon 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 achieve these goals and realize its net-zero vision while remaining focused on maintaining affordability, enhancing reliability, adopting emerging technologies and working constructively with policymakers, regulators, partners, investors, and Emera’s communities.

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

During the year ended December 31, 2020, the ongoing COVID-19 pandemic has affected all service territories in which Emera operates. Emera’s utilities provide essential services and continue to operate to meet customer demand. The Company’s priorities continue to be the reliable delivery of essential energy services while maintaining the health and safety of its customers and employees and supporting the communities Emera operates in.

The pandemic has generally resulted in lower load and higher operating costs than what otherwise would have been experienced at the Company’s utilities. Some of Emera’s utilities have been impacted more than others. However, on a consolidated basis these unfavourable impacts have not had a material financial impact to net earnings primarily due to a change in the mix of sales across customer classes. Lower commercial and industrial sales have been partially offset by increased sales to residential customers, which have a higher contribution to fixed cost recovery. Favourable weather in 2020, particularly in Florida, has further reduced the consolidated impact. The Company has not deferred any costs for future recovery as a result of the pandemic. Capital project delays and supply chain disruptions have also been minimal to date. Management continues to closely monitor developments related to COVID-19.

Governments world-wide have implemented measures intended to address the pandemic. These measures include travel and transportation restrictions, quarantines, physical distancing, closures of commercial and industrial facilities, shutdowns, shelter-in-place orders and other health measures. These measures are adversely impacting global, national and local economies. Global equity markets have experienced significant volatility and governments and central banks are implementing measures designed to stabilize economic conditions. The pace and strength of economic recovery is uncertain and may vary among jurisdictions.

In March 2020, Emera activated its company-wide pandemic and business continuity plans, including travel restrictions, directing employees to work remotely whenever possible, restricting access to operating facilities, physical distancing and implementing additional protocols (including the expanded use of personal protective equipment) for work within customers’ premises. In jurisdictions where it is safe to do so, some parts of the business have commenced a workplace re-entry strategy. The Company is monitoring recommendations by local and national public health authorities related to COVID-19 and is adjusting operational requirements as needed.

Emera’s utilities are working with customers on relief initiatives in response to the effect of the pandemic on customers’ ability to pay and their need for continued service. These initiatives have included the

temporary suspension of disconnection for non-payment of bills and the development of payment arrangements where necessary. In the third quarter of 2020, most of Emera’s utilities resumed disconnection processes for non-payment. As a result of the temporary suspension of disconnections, the Company’s utilities experienced an increase in the aging of customer receivables. This trend has begun to reverse as normal disconnection processes resume. There have been no significant customer defaults as a result of bankruptcies with many accounts being secured by deposits. As of December 31, 2020, adjustments to the allowance for credit losses have increased but have not had a material impact on earnings. The full impact of potential credit losses due to customer non-payment is not known at this time. The utilities are continuing to monitor customer accounts and are working with customers on payment arrangements.

The extent of the future impact of COVID-19 on the Company’s financial results and business operations cannot be predicted at this time and will depend on future developments, including the duration and severity of the pandemic, timing and effectiveness of vaccinations, further potential government actions and future economic activity and energy usage. In the first quarter of 2020, the Company updated its principal risks to reflect this uncertainty. For this risk update, refer to the “Risk Management and Financial Instruments” section of the MD&A and note 27 in the Audited Financial Statements, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

The Company has disclosed the impact of this uncertainty on its accounting estimates used in the preparation of the Audited Financial Statements. For further detail, refer to the “Critical Accounting Estimates” section of the MD&A, and the “Use of Management Estimates” section of note 1 in the Audited Financial Statements, which are each hereby incorporated by reference, copies of which are available electronically under Emera’s profile on SEDAR at www.sedar.com.

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

To date, the above have not had a material financial impact on the Company. Future impacts on the business will depend on future developments, including the duration and severity of the pandemic and the pace and strength of the economic recovery.

Refer to the outlook sections of the MD&A, by segment, for affiliate specific impacts, which is hereby incorporated by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com. These segment outlooks are based on the information currently available, however, the total impact of COVID-19 is unknown at this time.

Depending on the duration of the COVID-19 pandemic, the forecasted capital expenditures disclosed in the MD&A may be delayed due to supply chain disruptions, travel restrictions for contractors or the deferral of non-essential capital work. 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, 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 7,094 employees as at December 31, 2020, approximately 35 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 billion USD of assets, approximately 792,500 customers and 2,420 employees as at December 31, 2020.

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 equal to their cost of providing service, which includes 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, 2020, Tampa Electric owns 5,790 MW of generating capacity, of which 78 per cent is natural gas-fired, 12 per cent is coal and 10 per cent is solar. Tampa Electric owns 2,165 kilometres of transmission facilities and 19,250 kilometres of distribution facilities.

Tampa Electric’s approved regulated ROE range is 9.25 per cent to 11.25 per cent, based on an allowed equity capital structure of 54 per cent. An ROE of 10.25 per cent is used for the calculation of the return on investments recovered through cost recovery 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 the 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 the prudently incurred

clause-recoverable costs and amounts recovered from customers through electricity rates in a year are deferred to a corresponding regulatory asset or liability and recovered from or returned to customers in a subsequent year.

Storm Reserve

The storm reserve is for hurricanes and other named storms that cause significant damage to Tampa Electric’s system. As allowed by the FPSC, if the charges to the storm reserve exceed the storm liability, the excess is to be carried as a regulatory asset. Tampa Electric can draw on such reserve to fund restoration costs and can petition the FPSC to seek recovery of unfunded restoration costs over a 12-month period, or longer, as determined by the FPSC, as well as replenish the reserve.

Contribution to Consolidated Net Income

Florida Electric Utility’s contribution to consolidated net income was $372 million USD in 2020 (2019 - $316 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 2020, capital investments in the Florida Electric Utility segment were $1.0 billion USD (2019 – $1.1 billion USD). In 2021, capital investment is expected to be approximately $1.2 billion USD, including AFUDC. Capital projects include solar investments, continuation of the modernization of the Big Bend Power Station, storm hardening investments and AMI.

On February 18, 2020, Tampa Electric announced its intention to invest approximately $800 million USD in an additional 600 MW of new utility-scale solar photovoltaic projects by the end of 2023. For further information on this investment, refer to the “General Developments of the Business” section below.

Tampa Electric expects to invest approximately $850 million USD through 2023 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 its conservation cost recovery clause, 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 fossil fuel burning power plants with air emissions regulated by the Clean Air Act. Tampa Electric has achieved the emission-reduction levels called for in Phase I and Phase II of CAIR. CAIR was replaced by the Cross State Air Pollution Rule (CSAPR) which was most recently updated on October 26, 2016. Due to active engagement of Tampa Electric’s regulatory response groups, the EPA updated its modeling to include proper consideration of atmospheric dynamics and Florida is no longer subject to CSAPR.

On December 17, 2019, the EPA proposed to approve Florida’s Infrastructure State Implementation Plan (“SIP”) related to the 2015 ozone National Ambient Air Quality Standards (“NAAQS”), except for provisions related to interstate transport. On December 30, 2019, the EPA proposed to approve the remaining interstate transport elements of Florida’s SIP, along with similar submittals from nearby states

On March 5, 2020, Florida Department of Environmental Protection announced that Florida meets all of the requirements of the NAAQS.

The operation of fossil-fuel burning power plants also has material Clean Water Act implications and impacts by federal and state legislative initiatives. The final 316(b) rule became effective in October 2014 and seeks to reduce impingement and entrainment at cooling water intakes, including those at Big Bend and Bayside Power Stations. Requirements of the new rule will be determined by the federal and state regulatory agency review of the study elements performed to comply with the rule and in conjunction with the National Pollutant Discharge Elimination System permit renewals.

The final Effluent Limitations Guidelines were published on November 3, 2015, and establish limits for wastewater discharges from flue gas desulfurization processes, fly ash and bottom ash transport water, leachate from coal combustion residuals (“CCR”) impoundments, gasification processes, and flue gas mercury controls. New limits will require new technology at Big Bend Station before December 31, 2023. Since Polk Power Station disposes of gasification wastewater in onsite deep injection wells rather than discharging to surface water, the limits are not applicable.

The CCR Rule became effective on October 19, 2015 and covers the Big Bend Unit #4 Economizer Ash Ponds and the converted Units 1-3 slag fines pond. The slag pond was cleaned out and lined in 2020 for use as storm water storage. The Economizer Ponds Closure Project will be completed in 2021, by removing and disposing of the CCRs offsite and restoring the site to natural grade. The South Gypsum Storage Area Closure Project was completed as a component of the Big Bend Modernization in January 2020. There are no regulated CCR units at Polk or Bayside Power Stations.

Canadian Electric Utilities

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

NSPI

NSPI is the primary electricity supplier in Nova Scotia, providing electricity generation, transmission and distribution services to approximately 529,000 customers with $5.5 billion in assets and 2,054 employees as at December 31, 2020.

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’s approved regulated ROE range is 8.75 per cent to 9.25 per cent based on an actual five quarter average regulated common equity component of up to 40 per cent.

NSPI has a FAM, approved by the UARB, allowing NSPI to recover fluctuating fuel costs from customers through annual fuel rate adjustments. Differences between prudently incurred fuel costs and amounts recovered from customers through electricity rates in a given 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 (discussed in the “ENL – NSPML” section below). 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 2,433 MW of generating capacity, of which 43 per cent is coal-fired, 28 per cent is natural gas and/or oil, 20 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 27,000 km of distribution facilities, which includes distribution supply substations.

ENL

NSPML

Through its subsidiary, NSPML, ENL has invested $1.9 billion of equity, debt and working capital, including $209 million of AFUDC, in development of the Maritime Link. This investment consists of $546 million in equity, comprised of $443 million in equity contribution and $103 million of accumulated retained earnings, with the remaining being funded with working capital and debt. The project debt has been guaranteed by the Government of Canada.

The Maritime Link assets entered service on January 15, 2018 and provides for the transmission of energy and improved reliability and ancillary benefits, supporting the efficiency and reliability of both Provinces of Nova Scotia and Newfoundland and Labrador. The Maritime Link will transmit at greater capacity when the Lower Churchill project is complete, which is anticipated to take place in 2021.

Equity earnings contributions 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.

On December 16, 2020, the UARB approved NSPML’s 2021 interim cost assessment for recovery from NSPI of Maritime Link costs of approximately $172 million subject to a holdback of $10 million on similar terms as previously approved by the UARB and a potential long-term deferral of up to $23 million in depreciation expense dependent upon the timing of commencement of the NS Block. Recovery of this interim assessment began on January 1, 2021. NSPML expects to file a final cost assessment with the UARB upon commencement of the NS Block of energy from Muskrat Falls which is expected to take place in 2021.

LIL

ENL is a limited partner with Nalcor in LIL, with total project costs currently estimated at $3.7 billion. Equity earnings are recorded based on an annual ROE of 8.5 per cent of the equity invested. The ROE is set by the Newfoundland and Labrador Board of Commissioners of Public Utilities.

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 $628 million, comprised of $410 million in equity contribution and $218 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, including Muskrat Falls, are completed.

Cash earnings and return of equity will begin after commissioning of the LIL by Nalcor, 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 $221 million in 2020 (2019 - $229 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 2020 were $316 million (2019 - $396 million). In 2021, NSPI expects to invest approximately $370 million, including AFUDC, primarily in capital projects to support system reliability and hydroelectric infrastructure renewal investments.

The UARB prescribes and approves depreciation rates and regulated accounting policies. Depreciation rates are reviewed periodically. A settlement agreement on depreciation rates became effective on January 1, 2012.

NSPML

NSPML’s capital investments in 2020 were $7 million (2019 – $28 million). In 2021, NSPML expects to invest approximately $15 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.

The Government of Canada has laws and regulations that would compel the closure of coal plants before the end of their economic life and at the latest by 2030. The Canada-Nova Scotia Equivalency Agreement allows NSPI to achieve compliance with federal greenhouse gas (“GHG”) emissions regulations. The current Equivalency Agreement, which must be renewed in five-year increments, provides equivalency for the 2020-2024 period and outlines the framework for equivalency for the 2025 to 2040 period. At December 31, 2020, NSPI was in compliance with provincial requirements.

On November 19, 2020, the Government of Canada introduced Bill C-12, “Canadian Net-Zero Emissions Accountability Act”, which requires national targets be set for the reduction of GHG emissions in Canada, with the objective of attaining net-zero emissions by 2050. NSPI continues to work with the federal government on measures to address their carbon reduction goals.

On December 11, 2020, the federal government announced plans to increase the carbon tax in Canada starting in 2023, increasing $15 per tonne annually and reaching $170 per tonne by 2030, under the Greenhouse Gas Pollution Pricing Act (“GGPPA”). The GGPPA is a federal back stop for a price on carbon. As Nova Scotia prices carbon through the Nova Scotia Cap-and-Trade Program Regulations, it is NSPI’s expectation that Nova Scotia’s regulations will be considered equivalent to the proposed carbon tax under the GGPPA. NSPI will continue to work with the provincial government to understand their approach to changes to the Cap-and-Trade Program to address the federal government’s plans.

NSPI will receive its 2021 granted emissions allowances under the Nova Scotia Cap-and-Trade Program Regulations in Q1 2021. These allowances will be used in 2021 or allocated within the initial four-year compliance period that ends in 2022. NSPI is on track to meet the requirements of the program. 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

Over the past several years, the requirement to reduce Nova Scotia’s reliance upon 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 IPP’s. Energy from renewable sources will increase upon delivery of the NS Block of electricity transmitted through the Maritime Link from the Muskrat Falls hydroelectric project.

On March 17, 2020, Nalcor announced that it had paused construction activities at the Muskrat Falls site in response to the COVID-19 pandemic. Nalcor resumed work in May 2020 and continues to work toward construction completion and project commissioning in 2021. Due to the delay of the NS Block, NSPI did not achieve the provincially legislated target of 40 per cent of electric sales generated from renewable sources in 2020. This would have given rise to non-compliance except that on May 15, 2020, the provincial government provided NSPI with an alternative compliance plan, as permitted by the legislation, which requires NSPI to supply customers with at least 40 per cent of energy generated from renewable sources over the 2020 to 2022 period. NSPI expects to achieve this alternative compliance standard.

For further information on environmental regulations affecting NSPI, see NSPI’s 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 which is included in the Other Electric Utilities segment for Q1 2020 and all of 2019. For further detail, refer to the “Significant Items Affecting Earnings” and “Developments” 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.sedar.com.

BLPC

As at December 31, 2020, BLPC serves approximately 131,000 customers with $466 million USD of assets and a workforce of 406 employees. BLPC is regulated by the FTC, Barbados.

BLPC operates pursuant to a franchise to generate, transmit and distribute electricity on the island until 2028. In 2019, the Government of Barbados passed legislation amending the number of licenses required for the supply of electricity from a single integrated license which currently exists to multiple licenses for Generation, Transmission and Distribution, Storage, Dispatch and Sales. BLPC is negotiating the terms of the new licenses under the amended legislation.

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 through March 31, 2021. BLPC’s transmission system consists of 184 km of transmission lines, including major substations connected to the transmission and distribution system. The distribution system consists of 2,800 km of distribution lines which includes distribution supply substations.

GBPC

As at December 31, 2020, GBPC serves approximately 19,000 customers, with $320 million USD of assets and a workforce of 197 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. There is a fuel pass-through

mechanism and tariff review policy with new rates submitted every three years. GBPC’s approved regulated return on rate base was 8.34 per cent for 2020 (2019 - 8.5 per cent). In the first quarter of 2021, the GBPA approved GBPC’s regulated return on rate base of 8.37 per cent for 2021.

GBPC maintains insurance for its generation facilities. As with most utilities, its transmission and distribution networks are self-insured. In 2019 Hurricane Dorian restoration costs for GBPC’s self-insured 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.In Q4 2019, the Company recognized a non-cash impairment charge, primarily related to goodwill, of $26 million USD due to a decrease in expected future cash flows resulting from the impacts of Hurricane Dorian storm recovery and changes in the anticipated long term regulated capital structure of GBPC. No impairment charge related to GBPC was recognized in 2020. In March 2021, an agreement was reached with insurers for a claim with respect to the costs associated with rebuilding the Peel Street Generating plant, which was damaged during Hurricane Dorian, along with the costs associated with temporary generation required to maintain service to the island during the rebuilding of the plant.

In December 2016, the GBPA approved that the all-in rate for electricity (fuel and base rates) would be held at 2016 levels over the five-year period from 2017 through 2021. Any over-recovery of fuel costs during this period will be applied to the Hurricane Matthew regulatory deferral, until such time as the deferral is recovered. Should GBPC recover funds in excess of the Hurricane Matthew regulatory deferral, the excess will be placed in a new storm reserve. If balances remain within the Hurricane Matthew deferral at the end of the five years, GBPC will have the opportunity to request recovery from customers in future rates.

As a component of its regulatory agreement, GBPC has an earnings share mechanism to allow for earnings on rate base to be deferred to a regulatory asset or liability at the rate of 50 per cent of amounts below a 7.37 per cent (2020 - 7.34 per cent) return on rate base and 50 per cent of amounts above 9.37 per cent (2020 - 9.34 per cent) return on rate base respectively.

GBPC owns 98 MW of oil-fired generation, 138 kilometres of transmission facilities and 860 kilometers of distribution facilities. The utility has an additional 18 MW of capacity from rental units which are expected to be returned in the first half of 2021, when the generation units damaged by Hurricane Dorian are returned to service.

Domlec

As at December 31, 2020, Domlec serves approximately 34,000 customers, has a workforce of 226 employees and is regulated by the IRCD. Domlec is 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. 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 27 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.

Energy Sources and Generation

BLPC’s and GBPC’s energy sources for their respective electricity generation are primarily heavy fuel oil used for base load generation and light fuel oil used for peak generation. Domlec’s electricity generation is oil-fired and hydro.

With oil being the predominant fuel source for generation of electricity in the Caribbean, and with fuel costs directly passed through electricity rates to customers, any change in global fuel prices and resulting change in fuel costs will result in a similar change in customer rates and reported revenues. GBPC has implemented fuel hedging strategies to provide increased fuel cost certainty to customers. In support of

reducing carbon emissions and exposure to carbon-based fuel sources, more efficient and renewable energy generation and battery storage investments are being developed in the Caribbean.

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 $26 million USD in 2020 (2019 – $33 million USD). Adjusted for the 2019 non-cash impairment charge and mark-to-market, Other Electric Utilities’ contribution to consolidated net income was $24 million USD in 2020 (2019 – $57 million USD).

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 for 2020 were $111 million USD including $14 million USD invested in Emera Maine projects (2019 –$150 million USD). In 2021, capital investment is expected to be approximately $165 million USD. Forecasted capital investment is primarily in more efficient and cleaner sources of generation, including renewables and battery storage. BLPC expects to complete installation of a 33 MW power plant in 2021. This power plant will increase efficiency and bridge BLPC’s transition to increased renewable sources of generation.

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 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, 2020, PGS serves approximately 426,000 customers with $1.9 billion USD in assets and 680 employees. The PGS system includes approximately 22,200 kilometres of natural gas mains and 12,600 kilometres of service lines. Gas mains are distribution lines that serve as a common source of supply for more than one service line. Natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) was 2.1 billion therms in 2020.

For 2020, the approved ROE range for PGS was 9.25 per cent to 11.75 per cent, on an allowed equity capital structure of 54.7 per cent. An ROE of 10.75 per cent was used for the calculation of return on investments recovered through cost recovery clauses. Beginning in 2021, the approved ROE range is 8.9 per cent to 11.0 per cent, based on an allowed equity capital structure of 54.7 per cent and an ROE of 9.9 per cent will be 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, 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 all cast iron and bare steel pipe will be removed from its system by 2022, with replacement of obsolete plastic pipe continuing until 2028 under the rider.

NMGC

As at December 31, 2020, NMGC serves approximately 540,000 customers with $1.5 billion USD in assets and 698 employees. NMGC’s system includes 2,443 km of transmission lines and 17,243 km of distribution lines. Annual natural gas throughput was 948 million therms in 2020.

For 2020, the approved ROE for NMGC was 9.1 per cent, on an allowed equity capital structure of 52 per cent. New rates became effective August 2019 and were phased in over two years resulting in an annual revenue increase of approximately $3 million USD. In addition, NMGC’s weather mechanism became

effective October 2019. Beginning in 2021, the approved ROE 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. At the end of each PGAC year (twelve months ending in August) NMGC balances the PGAC for the year and flows the annual over or under balance into the following year. In extraordinary circumstances, NMGC can work with the NMPRC to handle large over or under-recovery balances. In February 2021, the State of New Mexico endured a severe weather event, which resulted in additional gas costs to NMGC and an under-recovery balance that could not reasonably be balanced in 2021. NMGC is filing a Motion for Extraordinary Relief, as permitted by the NMPRC rules, and anticipates recovering these extraordinary costs over a period greater than the 2022 PGAC year.

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.

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 will be 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 will seek recovery for the regulatory asset in its next rate case filing.

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 is constructing and 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 is anticipated to commence in January 2022. The capital investment is projected to be approximately $100 million USD, with the majority of the project investment completed through 2020. SeaCoast also jointly developed the 26.5 mile, 16-inch Callahan Pipeline with Peninsula Pipeline Co., an affiliate of Florida Public Utilities. The SeaCoast pipeline went into service in Q4 2020 providing long-term firm gas transportation service to PGS in the northeast Florida area with 2021 being the first full year of operation. SeaCoast’s portion of the capital investment in the Callahan Pipeline was approximately $30 million USD.

EBPC

EBPC owns Brunswick Pipeline, a regulated 145-km pipeline delivering re-gasified 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. Brunswick Pipeline is regulated by the CER, which has classified it as a Group II pipeline.

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 $122 million USD in 2020 (2019 –$139 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 in the Gas Utilities and Infrastructure segment in 2020 were $553 million USD. In 2021, capital investments is expected to be approximately $425 million USD, including AFUDC. PGS will make investments to expand its system and support customer growth. NMGC will complete the Santa Fe Mainline Looping project in January 2021 and will continue to invest in system improvements.

Environmental Considerations

Brunswick Pipeline is regulated by the CER and 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 Other include Emera Energy, which consists of:

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 recorded in “Intercompany revenue” 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 generally providing the greatest opportunity for earnings. EES is generally expected to deliver annual adjusted net earnings of $15 to $30 million USD ($45 to $70 million USD of margin), with the opportunity for upside when market conditions present.

Contribution to Consolidated Net Income and Adjusted Net Income

Other’s contribution to consolidated net income was $19 million in 2020, compared to a loss of $213 million in 2019. 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 $252 million compared to a loss of $286 million during the same period in 2019.

Capital Investment

Capital investments in the Other segment were $3 million in 2020 (2019 – $60 million). In 2021, capital investments in the Other segment is expected to be approximately $2 million.

GENERAL DEVELOPMENT OF THE BUSINESS

Three Year History and Changes Expected in 2021

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

During the year ended December 31, 2020, the ongoing COVID-19 pandemic has affected all service territories in which Emera operates. Emera’s utilities provide essential services and continue to operate to meet customer demand. The Company’s priorities continue to be the reliable delivery of essential energy services while maintaining the health and safety of its customers and employees and supporting the communities Emera operates in.

For more information on the COVID-19 Pandemic, refer to the “Introduction – COVID-19 Pandemic” section above.

Florida Electric Utility

Base Rate Adjustments

On February 1, 2021, Tampa Electric notified the FPSC of its intent to seek a base rate increase, reflecting incremental revenue requirements of approximately $280 million USD to $295 million USD, effective January 2022. Tampa Electric’s proposed rates include recovery for the costs of the first phase of the Big Bend modernization project, 225 MW of utility-scale solar projects, the AMI investment, and accelerated recovery of the remaining net book value of retiring assets. Tampa Electric also intends to seek approval for Generation Base Rate Adjustments of $130 million USD to recover the costs of the second phase of the Big Bend modernization project and additional utility-scale solar projects in subsequent years. These filing amounts are estimates until Tampa Electric completes and files its detailed case. Tampa Electric expects to file its detailed case on or after April 2, 2021, and a decision by the FPSC is expected by the end of 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 at December 31, 2020, Tampa Electric has invested approximately $820 million USD in 600 MW of utility-scale solar photovoltaic projects, which are recoverable through FPSC-approved SoBRAs. Tampa Electric expects to invest an additional $30 million USD in these projects through 2021. AFUDC is being earned on these projects during construction. The FPSC has approved SoBRAs representing a total of 600 MW or $104 million USD annually in estimated revenue requirements for in-service projects. The true-up filing for SoBRAs tranche 1 and 2 revenue requirement estimates that were included in base rates as of September 2018 and January 2019, respectively, was submitted on April 30, 2020, and the FPSC approved the amount on August 18, 2020. A $5 million USD true-up was returned to customers in 2020. The true-ups for SoBRA tranches 3 and 4 will be filed in 2021 and 2022, respectively.

In February 2020, Tampa Electric announced its intention to invest approximately $800 million USD in an additional 600 MW of new utility-scale solar photovoltaic projects by the end of 2023. As of December 31, 2020, Tampa Electric has invested approximately $213 million USD in these projects. AFUDC is being earned on these projects during construction. On completion of these projects, 22 per cent, or 1,250 MW, of Tampa Electric’s total generating capacity will be solar.

AMI Project

In September 2018, Tampa Electric announced its intention to invest approximately $235 million USD during 2018 through 2022 for its AMI project.

Big Bend Power Station Modernization

On May 24, 2018, Tampa Electric announced its intention to invest approximately $850 million USD through 2023 to modernize the Big Bend Power Station, of which $526 million USD has been invested through December 31, 2020. The modernization project will repower Big Bend Unit 1 with natural gas combined-cycle technology and eliminate coal as this unit’s fuel. On June 1, 2020, Tampa Electric retired the Unit 1 components that will not be used in the modernized plant. Tampa Electric plans to retire Big Bend Unit 2 in 2021 and Big Bend Unit 3 in 2023, as it is in the best interest of customers from economic, environmental risk and operational perspectives. For more information on the modernization of the Big Bend Power Station, refer to “Florida Electric Utility” 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.

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 submitted its storm protection plan with the FPSC on April 10, 2020. For more information on the SPP, refer to “Florida Electric Utility” 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.

Impact of Hurricane Irma and Tax Reform

In September 2017, Tampa Electric was impacted by Hurricane Irma and incurred restoration costs of $102 million USD. The amount charged to the storm reserve exceeded the balance in the reserve by $47 million USD. On December 28, 2017, Tampa Electric petitioned the FPSC for recovery of estimated restoration costs in excess of the storm reserve for several named storms and to replenish the reserve to the $56 million USD level that existed as of October 31, 2013. On March 1, 2018, the FPSC approved a settlement agreement filed by Tampa Electric authorizing the utility to net the amount of storm cost recovery against its return of estimated 2018 US tax reform benefits to customers, effective April 1, 2018. In Q1 2018, Tampa Electric recorded OM&G expense and a regulatory liability of $19 million USD to offset tax reform benefits. This deferral was amortized over the balance of the year as a credit against recognition of storm expense. In total, OM&G expense due to the allowed netting of the storm cost recovery with tax reform benefits, net of amortization of first quarter tax reform benefits, was $22 million USD for Q4 2018 and $103 million USD for the year ended December 31, 2018.

Tampa Electric’s final storm costs subject to netting were determined in a separate regulatory proceeding in 2019. On August 20, 2018, the FPSC approved a reduction in base rates of $103 million USD annually beginning in 2019 to reflect the impact of tax reform. On April 9, 2019, Tampa Electric reached a settlement agreement with consumer parties regarding eligible storm costs as a result of Hurricane Irma in 2017, which was approved by the FPSC on May 21, 2019. As a result, Tampa Electric refunded $12 million USD to customers in January 2020, resulting in minimal impact to the Consolidated Statements of Income contained in the Audited Financial Statements.

Canadian Electric Utilities

NSPI

Regulatory Matters

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 (“RSP”) 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.

The Maritime Link entered service on January 15, 2018 and NSPI started paying the UARB approved interim assessment payments to NSPML at that time. The UARB approved 2020 interim cost assessment recovery payment to NSPML was $145 million and as of December 31, 2020, $135 million has been paid. The payments were subject to a holdback of $10 million pending UARB agreement that a minimum of $10 million in benefits from the Maritime Link are realized for NSPI customers. If the $10 million in benefits is realized, the UARB will direct NSPI to pay the $10 million to NSPML for that year. If not realized, then the UARB will direct NSPI to pay to NSPML only that portion that is realized and the balance will be refunded to customers through NSPI’s FAM. On March 4, 2021, the UARB directed NSPI to pay $4 million of the 2020 holdback to NSPML, with the remaining to be refunded to customers through the FAM.

On December 16, 2020, the UARB approved NSPML’s 2021 interim cost assessment recovery from NSPI of Maritime Link costs of approximately $172 million subject to a holdback of $10 million with similar terms as previously approved by the UARB and a potential long-term deferral of up to $23 million in depreciation expense dependent upon the timing of commencement of the NS Block.

In response to the delayed timing of energy delivery from the Muskrat Falls project, which is being developed by Nalcor, the approved Maritime Link interim assessment payments reflected a reduction in NSPML’s assessment in each of 2018 and 2019, related to depreciation and amortization expenses. NSPI refunded the reduced 2018 NSPML assessment to customers in 2018 and 2019, by providing a credit to customers of $17 million and $35 million, respectively. The UARB’s decision to approve NSPI’s 2020-2022 fuel stability plan outlined the treatment of the reduced 2019 NSPML assessment of $52 million plus interest. The majority of the reduced assessment was refunded to most customers through a reduction incorporated into their 2020 rates and the remaining customers received a one-time on bill credit in 2020. As at December 31, 2020, $40 million plus interest has been refunded to customers, with the remaining $12 million plus interest to be returned to customers subsequent to 2022.

Pursuant to the FAM Plan of Administration, NSPI’s Fuel Costs are subject to independent audit. On August 21, 2020, the FAM audit results for fiscal 2018 and 2019 were filed with the UARB. A hearing was held in January 2021 and a decision is expected in Q2 2021.

On March 13, 2020, the UARB’s decision on the FAM audit findings and recommendations relating to fiscal 2016 and 2017 was publicly released. The final recommendations were endorsed by the UARB and did not include any disallowances.

For more information refer to the “Business Overview and Outlook – Canadian Electric Utilities”, “Regulated Fuel for Generation and Purchased Power” and “Regulatory Recovery Mechanisms” sections of Emera’s MD&A, 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 and Strategic Partnership with Nalcor on Muskrat Falls Projects

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 project is complete, which is anticipated to take place in 2021.

For information on the UARB’s approval of NSPI’s payments to NSPML, refer to the “NSPI - Regulatory Matters” section above.

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 “Developments” 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.

ECI

ICDU Acquisition

On October 13, 2017, Emera and ICDU announced that they had entered into a definitive agreement pursuant to which Emera would indirectly acquire all of the shares of ICDU that it did not own. Minority ICDU shareholders elected to receive BSD $8.85 in cash per common share or 0.913 Bahamas DRs. Each Bahamas DR represents one quarter of an Emera common share. On January 15, 2018, Emera completed the acquisition of the ICDU minority shareholders common shares for total consideration of $35 million USD and became the sole indirect owner of GBPC. The Bahamas DRs commenced trading on the BISX on January 22, 2018 and 1,814,135 Bahamas DRs were outstanding as at December 31, 2020.

Hurricane Dorian

On September 1, 2019, the Category 5 Hurricane Dorian struck Grand Bahama Island causing devastating wind and flood damage across the island. GBPC sustained damage to its generation, transmission and distribution assets. For more information on restoration costs, GBPC self-insured assets and impairment charges, refer to “Description of the Business – Other Electric Utilities – GBPC” above.

BLPC General Rate Review

On November 6, 2020, BLPC notified the FTC that it plans to file a general rate review application in the first half of 2021.

Gas Utilities and Infrastructure

PGS

Settlement Agreement

On June 8, 2020, PGS filed a petition for an increase in rates and service charges effective January 2021. On November 19, 2020, the FPSC approved a settlement agreement filed by PGS. The settlement agreement allows for an increase in base rates by $58 million USD annually effective January 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. This settlement agreement includes an allowed regulatory ROE range of 8.9 per cent to 11.0 per cent with a 9.9 per cent midpoint. It provides PGS the ability to reverse a total of $34 million USD of accumulated depreciation through 2023 and sets new depreciation rates going into effect January 1, 2021 that are consistent with PGS’ current overall average depreciation rate. 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

NMGC filed a rate case in December 2019. NMGC reached an unopposed stipulated settlement of the case which was approved by the NMPRC in December 2020. The new rates reflect the recovery of capital investment in pipelines and related infrastructure and results in an increase in revenue of approximately $5 million USD annually effective January 2021. The stipulated settlement agreement includes an allowed regulatory ROE of 9.375 per cent on an allowed equity capital structure of 52 per cent. Under the agreement base rates are frozen from January 1, 2021 to December 31, 2022, unless new federal tax rates are enacted, in which case NMGC can file for new rates to be effective earlier than January 1, 2023

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 remains available for issuance under the ATM Program.

During 2021, up to March 26, 2021, 810,100 common shares were issued under the ATM Program at an average price of $53.24 per share for gross proceeds of $43.1 million ($42.6 million net of issuance costs). As at March 26, 2021, an aggregate gross sales limit of $202 million remains available for issuance under the ATM program.

Preferred Share Issuance

On May 31, 2018, Emera issued 12 million Series H First Preferred Shares at $25.00 per share at an initial dividend rate of 4.9 per cent. The aggregate gross and net proceeds from the offering were $300 million and $295 million, respectively. The net proceeds of the preferred share offering were used for general corporate purposes.

On July 6, 2018, Emera announced it would not redeem the 10,000,000 Series C First Preferred Shares. The holders of the Series C First Preferred Shares had the right, at their option, to convert all or any of their Series C First Preferred Shares, on a one-for-one basis, into Series D First Preferred Shares on August 15, 2018 or to continue to hold their Series C First Preferred Shares. On August 8, 2018, Emera announced that, after having taken into account all conversion notices received from holders, no Series C First Preferred Shares would be converted into Series D First Preferred Shares.

On 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 March 24, 2021, Emera announced that it will issue 8 million Cumulative Minimum Rate Reset First Preferred Shares, Series J (the “Series J First Preferred Shares”) at $25.00 per share at an initial dividend rate of 4.25 per cent for aggregate gross proceeds of $200 million on a bought deal basis to a syndicate of underwriters. Emera has granted to the underwriters an option, exercisable at any time up to two business days prior to the closing of the offering, to purchase up to an additional 2,000,000 Series J First Preferred Shares at a price of $25.00 per share (the “Underwriters’ Option”). If the Underwriters’ Option is exercised in full, the aggregate gross proceeds to Emera will be $250 million. The offering is subject to the receipt of all necessary regulatory and stock exchange approvals. The aggregate gross proceeds of the offering will used for general corporate purposes. The Series J Preferred Shares are being offered to the public in Canada by way of a prospectus supplement to Emera’s short form base shelf prospectus dated March 12, 2021.

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, 2020, 251,430,226 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, 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, 2020, 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, 2020, 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 and Series H 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:

On March 24, 2020, S&P changed its corporate rating for Emera to BBB from BBB+ and at the same time changed the outlook on Emera to stable from negative. S&P states the reason for the change is due to Emera’s funds from operation (FFO) to debt not being consistently above the 12 per cent threshold required to maintain the BBB+ rating.

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 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 and Series H 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. Emera has provided annual dividend growth guidance of four to five per cent through to 2022. The Company targets a long-term dividend payout ratio of 70 to 75 per cent, and while the payout ratio is expected 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. Effective with the dividend payment of August 15, 2019, the discount was changed from 5 per cent to 2 per cent.

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 and Series H 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” and “EMA.PR.H”, 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 2020 are set out In Appendix “C” of this AIF.

At-The-Market Equity Program

On July 11, 2019, Emera established an 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 established under a prospectus supplement to the Company’s short-form base shelf prospectus which expires on July 14, 2021.

On November 17, 2020, Emera filed an amendment to its July 11, 2019 prospectus supplement which established its ATM Program. This amendment reflected changes in securities regulations related to ATM programs which were effective August 31, 2020. The amendment includes removal of the daily trading limit, which previously provided that the number of shares sold could not exceed 25 per cent of the daily trading volume of the shares.

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, 2020⁽¹⁾:

Officers

The Officers of Emera as at December 31, 2020 were as follows:

As at December 31, 2020, the Directors and Officers, in total, beneficially owned or controlled, directly or indirectly, 149,986 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 five members, all of whom are independent Directors: Kent M. Harvey (Chair), B. Lynn Loewen, Andrea S. Rosen, Richard P. Sergel and Jochen E. Tilk. 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 corporate director and is a Director of State Street Corporation. 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.

Jochen E. Tilk

Former Executive Chair of Nutrien Inc., a Canadian global supplier of agricultural products and services based in Saskatoon, Saskatchewan. Former President and Chief Executive Officer of Potash Corporation of Saskatchewan. Previously, Mr. Tilk spent 25 years with Inmet Mining Corporation, a Canadian-based, international metals company, with five of those years as the company’s President and Chief Executive Officer. Mr. Tilk is a director of AngloGold Ashanti Limited, a publicly listed international gold mining company, headquartered in Johannesburg, South Africa. He is also a director of the Princess Margaret Cancer Foundation, a not-for-profit organization. He is the former Chair of the board of directors of Canpotex Limited. He was a director of the Fertilizer Institute and the International Fertilizer Association. He received his Masters in Mining Engineering from Rheinisch-Westfälische Technische Hochschule, a research university located in Aachen, North Rhine-Westphalia, Germany.

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.

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, 2020, nor has it entered into any material contracts outside the ordinary course of business prior to the year ended December 31, 2020 that are still in effect as at the date of this AIF.

TRANSFER AGENT AND REGISTRAR

AST Canada 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 AST Canada’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.

APPENDIX “A” - Definitions of Certain Terms

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

As of December 31, 2020, the following series of First Preferred Shares have been authorized:

Series A, B, C, D, E, F, G, H and I 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, and H 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, in the case of the Series H preferred shares, to a fixed minimum reset of 4.90 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, and I 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, and H 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, and I 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 and H First Preferred Shares, have the right to convert any or all of their Series A, C, F, and H First Preferred Shares into an equal number of Series B, D, G and I First Preferred Shares, respectively. In addition, the Series A, C, F, and H First Preferred Shares may be automatically converted by Emera into Series B, D, G and I 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, and H First Preferred Shares outstanding, respectively.

Subject to automatic conversion conditions including the right of Emera to redeem the Series B, D, G, and I First Preferred Shares, the holders of Series B, D, G, and I First Preferred Shares have the right to convert any or all of their Series B, D, G, and I First Preferred Shares into an equal number of Series A, C, F, and H First Preferred Shares respectively. In addition, Series B, D, G, and I First Preferred Shares may be automatically converted by Emera into Series A, C, F, and H 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, and I 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 are redeemable by Emera in whole or in part, at the Company’s option without the consent of the holder, by the payment of: $25.75 per share if redeemed 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.

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, 2020, 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 2020

February 12, 2021

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:

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

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The Committee shall review and approve Emera’s hiring policy concerning partners or employees, as well as former partners and employees, of the present or former external auditors of Emera.

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

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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:

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the lead internal auditor. The Committee shall approve the charter, reporting relationship, activities, staffing, organizational structure, and budget of the internal audit department as changes are needed.

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:

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Nothing articulated herein is intended to assign to the Committee the Board’s responsibility to oversee Emera’s compliance with applicable laws or regulations or to expand applicable standards of liability under statutory or regulatory requirements for the Directors or the members of the Committee.

PART II

COMPOSITION

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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.

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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.

Exhibit 99.2

Management’s Discussion & Analysis

As at February 16, 2021

Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its subsidiaries and investments (“Emera”) during the fourth quarter of 2020 relative to the same quarter in 2019; the full year of 2020 relative to 2019 and selected financial information for 2018; and its financial position as at December 31, 2020 relative to December 31, 2019. Throughout this discussion, “Emera Incorporated”, “Emera” and “Company” refer to Emera Incorporated and all of its consolidated subsidiaries and investments. The Company’s activities are carried out through five reportable segments: Florida Electric Utility, Canadian Electric Utilities, Other Electric Utilities, Gas Utilities and Infrastructure, and Other.

This discussion and analysis should be read in conjunction with the Emera Incorporated annual audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2020. Emera follows United States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”).

The accounting policies used by Emera’s rate-regulated entities may differ from those used by Emera’s non-rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities, revenues and expenses. At December 31, 2020, Emera’s rate-regulated subsidiaries and investments include:

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

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

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

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FORWARD-LOOKING INFORMATION

This MD&A contains “forward-looking information” and statements which reflect the current view with respect to the Company’s expectations regarding future growth, results of operations, performance, carbon emissions reduction goals, business prospects and opportunities, and may not be appropriate for other purposes within the meaning of applicable Canadian securities laws. All such information and statements are made pursuant to safe harbour provisions contained in applicable securities legislation. The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecast”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “targets”, “will”, “would” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management’s current beliefs and is based on information currently available to Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the time at which, such events, performance or results will be achieved.

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

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

INTRODUCTION AND STRATEGIC OVERVIEW

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 gas and electric services in designated territories under franchises and are overseen by regulatory authorities. Emera’s strategic focus continues to be to safely deliver 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 return on that equity (“ROE”) as approved through regulation. Earnings are also affected by sales volumes and operating expenses.

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Emera’s $7.4 billion capital investment plan over the 2021-to-2023 period, and the potential for additional capital opportunities of $1.2 billion over the same period, results in a forecasted rate base growth of 7.5 per cent to 8.5 per cent through to 2023. The capital investment plan continues to include significant investments across the portfolio in renewable and cleaner generation, 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 will predominantly be funded in equity capital markets through the dividend reinvestment plan and issuance of common and preferred equity. Maintaining investment-grade credit ratings is a priority of management.

Emera has provided annual dividend growth guidance of four to five per cent through to 2022. 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.

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 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 at Tampa Electric, and the modernization of the Big Bend Power Station at Tampa Electric. Emera’s utilities are also investing in reliability projects and replacing aging infrastructure. All of these projects demonstrate Emera’s strategy of safely delivering cleaner, reliable, and affordable energy for its customers.

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

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Emera seeks to achieve these goals and realize its net-zero vision while remaining focused on maintaining affordability, enhancing reliability, adopting emerging technologies and working constructively with policymakers, regulators, partners, investors, and Emera’s communities.

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

NON-GAAP FINANCIAL MEASURES

Emera uses financial measures that do not have standardized meaning under USGAAP and may not be comparable to similar measures presented by other entities. Emera calculates the non-GAAP measures by adjusting certain GAAP measures for specific items the Company believes are significant, but not reflective of underlying operations in the period. These measures are discussed and reconciled below.

Adjusted Net Income

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

The MTM adjustments are a result of the following:

Management believes excluding from net income the effect of these MTM valuations and changes thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows and ongoing operations of the business, and allows investors to better understand and evaluate the business. Management and the Board of Directors exclude these MTM adjustments for evaluation of performance and incentive compensation. For further detail on MTM adjustments, refer to the “Consolidated Financial Review” section and the “Financial Highlights” sections for Other Electric Utilities and Other segments.

In 2020, the Company recognized a gain on the sale of Emera Maine. Management believes excluding this from net income better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the business. Refer to the “Significant Items Affecting Earnings” and “Developments” sections for further detail related to the sale of Emera Maine. While the gain on sale has been excluded from adjusted earnings, earnings for the Other Electric Utilities segment only includes earnings from Emera Maine up to the date of its sale in Q1 2020.

In 2019 and 2020, the Company recognized certain non-cash impairment charges. Management believes excluding from net income the effect of these charges better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the Company. For further details, refer to the “Significant Items Affecting Earnings”, “Financial Highlights – Other Electric Utilities” and “Financial Highlights – Other” sections.

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

EBITDA and Adjusted EBITDA

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

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

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

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