Exhibit 99.1

Management’s Discussion & Analysis

As at May 12, 2020

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 first quarter of 2020 relative to the same quarter in 2019; and its financial position as at March 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 unaudited condensed consolidated interim financial statements and supporting notes as at and for the three months ended March 31, 2020; and the Emera Incorporated annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2019. 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 March 31, 2020, Emera’s rate-regulated subsidiaries and investments include:

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On March 24, 2020, the Company completed the sale of Emera Maine. Refer to the “Significant Items Affecting Q1 Earnings” and “Developments” sections for further details.

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, 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 are discussed in the “Business Overview and Outlook” section of the MD&A and may also include: 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 is 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 experienced stable regulatory policies and economic conditions.

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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 has a $7.5 billion capital investment plan over the 2020-to-2022 period and the potential for additional capital opportunities of $200 million to $500 million over the forecast period, resulting in a forecasted rate base growth of 8 per cent through to 2022. Management continues to review the timing of capital expenditures in light of the evolving COVID-19 pandemic. This plan includes significant investments across the portfolio in renewable and cleaner generation, infrastructure modernization and customer-focused technologies. This planned capital investment 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 the equity capital markets through the dividend reinvestment plan and the 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 in 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 investment 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, complex regulatory environments and the trend towards de-carbonization. Renewable generation and battery storage are becoming both more affordable and efficient. 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 these trends. Emera’s strategy is to fund investments in renewable 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 finding cleaner ways to meet the energy needs of its customers while keeping rates affordable.

Emera is committed to world-class safety, operational excellence, good governance, excellent customer service, reliability, being an employer of choice, and building constructive relationships with regulators, stakeholders and the communities where we operate.

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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 and impacts in Q1 2020 of the gain on sale of Emera Maine and the impairment losses on certain other assets.

The MTM adjustments are a result of the following:

Management believes excluding from net income the effect of these mark-to-market 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 mark-to-market adjustments for evaluation of performance and incentive compensation.

Refer to the “Consolidated Financial Review” section and the “Financial Highlights” sections for Other Electric Utilities and Other segments, for further details on mark-to-market adjustments.

In Q1 2020, the Company completed the sale of Emera Maine and recognized impairment losses on certain other assets. Management believes excluding these 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 Q1 Earnings” and “Developments” sections for further details related to the sale of Maine. While we have excluded the gain on sale from adjusted earnings, earnings for the Other Electric Utilities segment will not include earnings from Maine for the balance of the year, which were $27 million USD in 2019.

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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 mark-to-market and amortization adjustments, and the gain on sale and impairment charges, recognized in Q1 2020, 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:

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

CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Q1 Earnings

Gain on Sale and Impairment Charges

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 $586 million ($321 million after tax or $1.31 per common share), net of transaction costs, was recognized in “Other income” on the Condensed Consolidated Statements of Income. Refer to the “Developments” section for further details. In addition, impairment charges of $22 million ($23 million after tax) were recognized on certain other assets in Q1 2020.

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Earnings Impact of After-Tax Mark-to-Market Gains and Losses

After-tax mark-to-market gains decreased $56 million to $32 million in 2020 compared to $88 million in 2019, mainly due higher amortization of gas transportation assets in 2020 and larger reversal of mark-to-market losses in 2019, partially offset by changes in existing positions on gas contracts in Emera Energy. The decrease is also due to mark-to-market losses related to foreign exchange cash flow hedges entered in Q1 2020 to manage foreign exchange earnings exposure.

Q1 2019 Sale of NEGG and Bayside facilities

In Q1 2020, earnings contribution from Emera Energy Generation was $24 million lower than in 2019 due to the sale of the New England Gas Generating (“NEGG”) and Bayside generation facilities completed in March 2019.

The following table highlights significant changes in adjusted net income from 2019 to 2020.

Refer to the “Financial Highlights” section for further details of reportable segment contributions.

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Refer to the “Consolidated Cash Flow Highlights” section for further discussion of cash flow.

These impacts were partially offset by increases of:

Operating Expenses

For the first quarter of 2020, operating expenses decreased $60 million compared to the first quarter of 2019 due to:

These impacts were partially offset by an increase of:

Other Income (Expenses), Net

The increase in other income (expenses), net for the first quarter in 2020, compared to the first quarter of 2019, was primarily due to the pre-tax gain on sale of Emera Maine, partially offset by impairment charges on certain other assets recognized in Q1 2020.

Income Tax Expense

The increase in income tax expense for the first quarter of 2020 compared to the first quarter of 2019 was primarily due to the gain on sale of Emera Maine and the revaluation of net deferred income tax assets resulting from the enactment of a lower Nova Scotia provincial corporate income tax rate in Q1 2020. This was partially offset by decreased income before provision for income taxes, excluding the gain on sale of Emera Maine, and the recognition of corporate income tax recovery deferred as a regulatory liability in 2018 at BLPC.

Net Income and Adjusted Net Income Attributable to Common Shareholders

For the first quarter of 2020, net income attributable to common shareholders was favourably impacted by the $321 million after-tax gain on sale of Emera Maine, and unfavourably impacted by the $56 million decrease in after-tax mark-to-market gains primarily related to Emera Energy and after-tax impairment charges. Absent the net gain on sale of Emera Maine, the unfavourable mark-to-market changes and impairment charges recognized in Q1 2020, adjusted net income attributable to common shareholders decreased $31 million. The decrease was due to lower contributions from Emera Energy (as a result of the sale of NEGG in Q1 2019 and decreased marketing and trading margin), revaluation of deferred taxes due to a reduction in the Nova Scotia corporate income tax rate and the 2019 gain on sale of property in Florida. These were partially offset by an increased contribution from Tampa Electric and recognition of deferred income tax at BLPC.

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Earnings and Adjusted Earnings per Common Share – Basic

Earnings per common share – basic were higher for the first quarter due to higher earnings as discussed above. Adjusted earnings per common share – basic were lower for the first quarter due to lower earnings as discussed above and the impact of the increase in the weighted average shares outstanding.

Effect of Foreign Currency Translation

Emera operates internationally, including in Canada, the US and various Caribbean countries. As such, the Company generates revenues and incurs expenses denominated in local currencies which are translated into Canadian dollars for financial reporting. Changes in translation rates, particularly in the value of the US dollar against the Canadian dollar, can positively or adversely affect results.

Earnings from Emera’s foreign operations are translated into Canadian dollars. In general, Emera’s earnings benefit from a weakening Canadian dollar and are adversely impacted by a strengthening Canadian dollar. The impact of foreign exchange in any period is driven by rate changes, the timing of earnings from foreign operations during the period, the percentage of earnings from foreign operations in the period and the impact of foreign exchange cash flow hedges entered to manage foreign exchange earnings exposure.

Results of foreign operations are translated at the weighted average rate of exchange and assets and liabilities of foreign operations are translated at period end rates. The relevant CAD/US exchange rates for 2020 and 2019 are as follows:

Weakening of the CAD exchange rates increased earnings by $5 million and adjusted earnings by $1 million in Q1 2020 compared to Q1 2019.

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

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

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

(2) Includes Emera Energy’s US dollar adjusted net income from Emera Energy Services, Bear Swamp, interest expense on Emera Inc.’s US dollar denominated debt and in 2019 net income from NEGG.

(3) Amounts above do not include the impact of mark-to-market.

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BUSINESS OVERVIEW AND OUTLOOK

COVID-19 Pandemic

In Q1 2020, the ongoing COVID-19 pandemic impacted all the service territories in which Emera operates. To date, COVID-19 has not had a material financial impact on the Company, Emera’s utilities provide essential services and continue to operate and meet customer demand. The Company’s top priority continues to be the health and safety of its customers and employees. 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 spaces 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 weakness. Governments and central banks are implementing measures designed to stabilize economic conditions.

Emera has 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. The Company is monitoring recommendations by local and national public health authorities related to COVID-19 and is adjusting operational requirements as needed.

The extent of the future impact of COVID-19 on the Company’s financial results and business operations cannot be predicted at this time and will depend on future developments, including the duration and severity of the pandemic, further potential government actions and future economic activity and energy usage. The Company has updated its principal risks to reflect this uncertainty. Refer to the “Risk Management and Financial Instruments” section and note 21 in the condensed consolidated financial statements for this risk update. The Company has disclosed the impact of this uncertainty on its accounting estimates used in the preparation of the financial statements. Refer to the “Critical Accounting Estimates” section, and the “Use of Management Estimates” section of note 1 in the condensed consolidated financial statements for further details.

Potential future impacts on the business are anticipated to include the following:

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Refer to the outlook sections by segment below for discussion of utility-specific impacts. These segment outlooks are based on the information currently available, however, the total impact of COVID-19 is unknown at this time due to uncertainties related to the duration and severity of the pandemic.

Depending on the duration of the COVID-19 pandemic, the forecasted capital expenditures disclosed below may be delayed due to supply chain disruptions, travel restrictions for contractors or the deferral of non-essential capital work, if required. 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. Refer to the “Liquidity and Capital Resources” section for further details.

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 currently anticipates earning within its allowed ROE range in 2020 and expects rate base to be higher than 2019. Favourable weather in Q1 2020 has more than offset the impacts on revenues as a result of COVID-19. Based on Q1 results and current estimates of COVID-19 impacts, and assuming normal weather for the remainder of the year, Tampa Electric expects customer growth rates and volumes to be negatively impacted by expected declines in economic activity in Florida, resulting in overall sales volumes for the year being similar or slightly lower than in 2019. However, current expected outcomes and actual results may differ given the many uncertainties related to the pandemic and its economic impact.

On October 3, 2019, the FPSC issued a rule to implement a storm protection plan 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. The FPSC is expected to rule on the plan in late 2020.

On April 28, 2020 the FPSC approved Tampa Electric’s request for a mid-course adjustment to its fuel and capacity charges due to a decline in expected fuel commodity and capacity costs in 2020. The adjustment will be effective beginning with June 2020 customer bills and will result in lower rates for the balance of the year, including an acceleration of the return of these savings in the first three months.

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. Refer to the “Developments” section for further details.

Planned capital expenditures in the Florida Electric Utility segment for 2020 remain unchanged at approximately $1.0 billion USD (2019 - $1.1 billion USD), including AFUDC. Capital projects include solar investments, continuation of the modernization of the Big Bend Power Station, storm hardening investments, and advanced metering infrastructure (“AMI”).

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Canadian Electric Utilities

Canadian Electric Utilities includes:

NSPI

NSPI anticipates earning within its allowed ROE range in 2020. Sales volumes and earnings are expected to be lower than 2019 due to the impact of the COVID-19 pandemic on Nova Scotia’s economy. NSPI expects a decrease in sales volumes primarily in the commercial and industrial classes, partially offset by an increase in residential sales volumes, which have a higher contribution to fixed cost recovery. The anticipated deferral of capital investment, discussed below, will have a corresponding decreasing effect on NSPI’s expected rate base growth in the current year.

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

In Q1 2020, NSPI received its 2020 granted emissions allowances under the Nova Scotia Cap-and-Trade Program Regulations. These 2020 allowances will be used in 2020 or allocated within the initial four-year compliance period that ends in 2022. At March 31, 2020, 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.

Over the past several years, the requirement to reduce Nova Scotia’s reliance upon higher carbon and greenhouse gas emitting sources of energy has resulted in NSPI making a significant investment in renewable energy sources and purchasing renewable energy from independent power producers. NSPI will have an increase in energy from renewable sources upon delivery of the Nova Scotia block (“NS Block”) of electricity transmitted through the Maritime Link from the Muskrat Falls hydroelectric project.

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On March 17, 2020, Nalcor announced that it had temporarily paused construction activities at the Muskrat Falls site in response to the COVID-19 pandemic. Due to the unpredictability of the course of the pandemic, Nalcor is currently unable to provide an updated construction schedule. Refer to the “ENL – Impact of COVID-19 on Muskrat Falls and LIL” section below for further details. Should there be a delay in the delivery of the NS Block beyond 2020, NSPI’s ability to achieve the provincially legislated target of 40 per cent electricity generated from renewable sources in 2020 could require the sourcing of alternate qualifying energy. NSPI is working with the provincial government on options to address this potential risk.

As a result of the measures taken to limit the spread of COVID-19, there are restrictions on completing non-essential capital projects. NSPI anticipates this will result in a reduction in its 2020 capital investments from $375 million to approximately $275 million. The $100 million of capital investments will be deferred to 2021 and 2022. Capital investment for 2019, including AFUDC, was $396 million.

ENL

Equity earnings from NSPML and LIL are expected to be higher in 2020, compared to 2019. Both the NSPML and LIL investments are recorded as “Investments subject to significant influence” on Emera’s Condensed Consolidated Balance Sheets.

NSPML

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.

NSPML has UARB approval to collect approximately $145 million (2019—$111 million) from NSPI for the recovery of costs associated with the Maritime Link in 2020, which is included in NSPI rates. NSPML expects to file a final capital cost application for the Maritime Link with the UARB upon commencement of the NS Block of energy from Muskrat Falls. As a result of the potential delay of the NS Block, NSPML’s final capital cost application will be delayed. Consequently, NSPML anticipates making an application with the UARB in 2020 to reset rates for recovery of costs in 2021.

In 2020, NSPML expects to invest approximately $20 million (2019—$28 million) in capital.

LIL

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 $591 million, comprised of $410 million in equity contribution and $181 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.

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Impact of COVID-19 on Muskrat Falls and LIL

On March 17, 2020, Nalcor announced that it had temporarily paused construction activities at the Muskrat Falls site in response to the COVID-19 pandemic. As a result of the effects of COVID-19 on project execution, Nalcor has declared force majeure under various project contracts, including formal notification to NSPML. Due to the unpredictable nature of the COVID-19 pandemic, Nalcor is currently unable to provide an updated completion schedule for Muskrat Falls or LIL until there is greater certainty. Nalcor has expressed its desire to resume work at site as soon as it is safe to do so for its employees, contractors and associated communities.

Other Electric Utilities

Other Electric Utilities includes:

Removing the impact of the GBPC impairment charge recognized in 2019, Other Electric Utilities’ earnings are expected to decrease over the prior year. This decrease is due to lower earnings contribution from Emera Maine as a result of the sale in March 2020, and lower earnings from the Caribbean utilities.

Earnings from the Caribbean utilities are expected to be lower due to the impact of COVID-19 on local economies. Tourism and associated support businesses have been significantly impacted by the suspension of international travel, with many businesses temporarily closed. As a result, earnings from both BLPC and Domlec are expected to be lower than in 2019. The expected decrease in BLPC’s earnings will be partially offset by the Q1 2020 recognition of a $6.9 million USD corporate income tax recovery which was deferred as a regulatory liability in 2018. GBPC’s earnings are expected to be consistent with 2019 earnings which were lower than normal as a result of Hurricane Dorian. The impact of COVID-19 on GBPC is expected to be partially offset by recovery of load following Hurricane Dorian. The decrease in earnings from the Caribbean utilities is expected to be in the range of approximately $3 million to $8 million USD depending on the extent and duration of the pandemic’s impact on local economies.

On April 16, 2020, S&P Global Ratings (“S&P”) lowered its long-term foreign and local currency ratings on The Bahamas. The downgrade was driven by the uncertainty around the duration of the COVID-19 pandemic and the strength of the recovery. The downgrade is not currently expected to have a material financial impact on GBPC.

On September 1, 2019, Hurricane Dorian struck Grand Bahama Island causing significant damage across the island. In January 2020, the GBPA approved the recovery of approximately $15 million USD of restoration costs related to GBPC’s self-insured assets. As of March 31, 2020, $13 million USD of these costs were incurred, and recorded as a regulatory asset. Recovery of the regulatory asset, due to start on April 1, 2020, has been temporarily suspended as a result of the economic impacts of COVID-19 on Grand Bahama.

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In 2020, capital expenditures in the Other Electric Utilities segment are forecasted to be approximately $130 million USD (including $14 million USD invested in Emera Maine projects supporting normal system reliability prior to completion of the sale) (2019 – $150 million USD). Completion of BLPC’s 33MW diesel engine installation, expected by mid-2020, will be delayed until travel restrictions, implemented by the government in response to COVID-19, are lifted for construction work.

Gas Utilities and Infrastructure

Gas Utilities and Infrastructure includes:

Earnings from the gas utilities are anticipated to be lower than in 2019 due to impact of the COVID-19 pandemic.

PGS anticipates earning below its allowed ROE range in 2020. PGS sales volumes are expected to be lower than in 2019 as a result of the economic impact of COVID-19 in Florida. Beginning mid-March, PGS sales volumes have shown a decreasing trend as a result of the impact of government quarantine measures on commercial activity and tourism. Prior to the impact of COVID-19, PGS anticipated it would earn below its allowed ROE range in 2020 primarily due to significant capital investments and related growth in rate base. Therefore, as a result of forecasted revenue requirements being higher than what is in current rates, on February 7, 2020, PGS notified the FPSC that it was planning to file a base rate proceeding in April 2020 for new rates effective January 2021. Due to the COVID-19 pandemic, in early April 2020, PGS requested and received an extension from the FPSC to file this proceeding by June 8, 2020.

NMGC anticipates earning at or slightly below its allowed ROE in 2020 and expects rate base to be higher than 2019. Assuming normal weather, NMGC sales volumes are expected to decrease, as 2019 energy sales benefited from favourable weather in the first half of the year. NMGC sales volumes to date have not been significantly impacted by COVID-19. Depending on the duration of COVID-19 related restrictions, industrial and commercial sales volumes are expected to decrease. Earnings from NMGC are also expected to be lower as a result of the 2019 recognition of tax reform benefits, and the approved change in treatment of net operating loss (“NOL”) carryforwards in 2019, which contributed a total of $14 million USD to earnings last year.

In 2020, capital expenditures in the Gas Utilities and Infrastructure segment are expected to be approximately $600 million USD (2019 - $331 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 2020 and will continue to invest in system improvements. SeaCoast will continue to invest in the Seminole Pipeline and the Callahan Pipeline with approximately $100 million USD expected to be invested in 2020. The Seminole and Callahan Pipelines remain on schedule with total costs of approximately $110 million USD and $32 million USD, respectively.

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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:

In 2019, the Company completed the sale of assets previously reported in this segment including the sale of its NEGG and Bayside facilities in March 2019 and the sale of its Emera Utility Services equipment and inventory in December 2019. These operations contributed $20 million to earnings in 2019.

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, corporate human resources activities, acquisition and disposition related costs, gains or losses on select assets sales, and gains or losses on foreign exchange cash flow hedges entered to manage foreign exchange earnings exposure. 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.

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. The business 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. EES expects that the COVID-19 related economic slowdown could impact gas supply/demand and result in lower absolute pricing and volatility in its core geography for some months. This would reduce opportunity for the business, which the Company expects would result in earnings at the lower end of the normal range in 2020.

The Other segment is expected to contribute positively to earnings in 2020 due to the gain on sale of Emera Maine recognized in earnings in Q1 2020. Absent this gain, the adjusted net loss from the Other segment is expected to increase over the prior year. This increase is primarily due to decreased tax recoveries and increased interest due to increased borrowings. The decrease in tax recoveries is due to the revaluation of deferred income tax assets at the lower Nova Scotia corporate income tax rate enacted in March 2020. These impacts are anticipated to be partially offset by increased EES contribution.

In 2020, capital expenditures in the Other segment are expected to be approximately $40 million (2019 - $63 million), including investment in contracted energy infrastructure.

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DEVELOPMENTS

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), including cash proceeds of $1.4 billion, transferred debt and a working capital adjustment. A gain on sale of $586 million ($321 million after tax), net of transaction costs, was recognized in the Other segment and included in “Other income” on the Condensed Consolidated Statements of Income. Proceeds from the sale are being used to support capital investment opportunities within Emera’s regulated utilities and to reduce corporate debt.

Tampa Electric Solar Investment

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. On completion of these projects, approximately 22 per cent or 1,250 MW of Tampa Electric’s total generating capacity will be solar.

(1) In Q1 2020, 982,982 common shares were issued under Emera’s at-the-market program (“ATM program”) at an average price of $59.79 per share for gross proceeds of $58.8 million ($58 million net of issuance costs). As at March 31, 2020, an aggregate gross sales limit of $441.2 million remains available for issuance under the ATM program.

As at May 8, 2020 the amount of issued and outstanding common shares was 244.7 million.

The weighted average shares of common stock outstanding – basic, which includes both issued and outstanding common stock and outstanding deferred share units, for the three months ended March 31, 2020 was 244.7 million (2019 – 236.4 million).

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Florida Electric Utility’s CAD contribution to consolidated net income increased $18 million to $79 million in Q1 2020, compared to $61 million in Q1 2019. Earnings increased due to higher base revenues as a result of favourable weather, customer growth and the in-service of solar generation projects. This increase was partially offset by higher depreciation expense and higher interest expense as a result of higher capital investments.

The impact of the change in the foreign exchange rate increased Q1 2020 CAD earnings by $1 million.

Operating Revenues – Regulated Electric

Electric revenues increased $9 million to $421 million in Q1 2020 compared to $412 million in Q1 2019. Revenues increased due to higher base revenues related to favourable weather, customer growth and the in-service of solar generation projects, partially offset by lower clause revenues. A significant portion of the weather impact occurred during the last half of March 2020 resulting in an increase in unbilled revenues in Q1 2020, compared to Q1 2019. While operating revenues include both billed and unbilled

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revenues, Q1 2020 electric sales volumes, in the table below, do not reflect this increase as they are calculated based on billed hours only.

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

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

(1) Electric sales volumes are calculated based on billed hours only. GWh related to unbilled revenues are excluded.

Average fuel cost per MWh decreased in Q1 2020, compared to Q1 2019, primarily due to increased use of lower-cost natural gas and zero fuel cost solar generation.

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NSPI

Operating Revenues – Regulated Electric

Operating revenues increased $15 million to $458 million in Q1 2020 compared to $443 million in Q1 2019. Revenues increased due to the reduced Maritime Link assessment included in 2019 rates to be returned to customers in subsequent years, and increased fuel-related pricing. This was partially offset by decreased sales volumes due to weather, decreased export sales and decreased other, industrial and commercial class sales volumes.

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

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Average fuel cost per MWh increased in Q1 2020, compared to Q1 2019, primarily due to a change in generation mix resulting from higher natural gas consumption partially offset by lower generation from solid fuel and a decrease in purchased power.

NSPI’s FAM regulatory liability balance decreased $3 million from $115 million at December 31, 2019 to $112 million at March 31, 2020 primarily due to the refund of prior years’ over-recovery of fuel costs and reduced Maritime Link assessment to customers. This was partially offset by over-recovery of current period fuel costs.

Other Electric Utilities

All amounts are reported in USD, unless otherwise stated.

On March 24, 2020, Emera completed the sale of Emera Maine. The Company continued to record depreciation on these assets through the transaction closing date, as the depreciation continued to be reflected in customer rates and was reflected in the carryover basis of the assets on close. Refer to the “Significant Items Affecting Q1 Earnings” and “Developments” sections for further details.

(1) Regulated fuel for generation and purchased power includes transmission pool expense.

Other Electric Utilities’ adjusted contribution is summarized in the following table:

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Excluding the change in mark-to-market, Other Electric Utilities’ CAD contribution to consolidated net income increased by $4 million to $20 million in Q1 2020, compared to $16 million in Q1 2019. ECI’s contribution increased due to recognition of a previously deferred corporate income tax recovery related to the enactment of a lower corporate income tax rate in December 2018 at BLPC. Emera Maine contribution decreased due to unseasonably warm weather and lower regional transmission revenues. The foreign exchange rate had minimal impact on Other Electric Utilities for the three months ended March 31, 2020.

Operating Revenues – Regulated Electric

Operating revenues decreased $9 million to $127 million in Q1 2020 compared to $136 million in Q1 2019, primarily due to unseasonably warm weather at Emera Maine and lower sales at GBPC due to the impact of Hurricane Dorian. These were partially offset by increased sales volumes at Domlec and BLPC and higher fuel revenue at BLPC.

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

(1) Other revenue includes amounts recognized relating to Emera Maine’s FERC transmission rate refunds and other transmission revenue adjustments.

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Gas Utilities and Infrastructure’s CAD contribution to consolidated net income increased $3 million to $70 million in Q1 2020 compared to $67 million in Q1 2019. Earnings from PGS and NMGC were consistent quarter-over-quarter as customer growth, higher return on investment in Cast Iron/Bare Steel replacement rider at PGS and lower NMGC depreciation rates were offset by unfavourable weather at NMGC, higher OM&G expenses, and higher depreciation at PGS.

The foreign exchange rate had minimal impact for the three months ended March 31, 2020.

Operating Revenues – Regulated Gas

Operating revenues decreased $19 million to $250 million in Q1 2020 compared to $269 million in Q1 2019. This decrease resulted from lower clause-related revenues at PGS and NMGC, unfavourable weather in New Mexico and lower off-system sales at PGS, partially offset by customer growth at PGS.

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

(1) Industrial includes sales to power generation customers.

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

(3) Excludes $11 million of finance income from Brunswick Pipeline (2019 – $11 million).

Regulated Cost of Natural Gas

Regulated cost of natural gas decreased $22 million to $81 million in Q1 2020, compared to $103 million in Q1 2019, due to lower commodity costs at PGS and NMGC.

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Gas sales by type are summarized in the following table:

Excluding the decrease in mark-to-market gain, the gain on sale and impairment charges recognized on certain other assets, Other’s contribution to consolidated net income decreased $52 million to a loss of $68 million for Q1 2020, compared to Q1 2019. This was primarily due to the impact of the sale of NEGG and Bayside Power in 2019, decreased marketing and trading margin, revaluation of net deferred income tax assets resulting from the enactment of a lower Nova Scotia provincial corporate income tax rate in Q1 2020, the 2019 sale of property in Florida and increased OM&G in Corporate. These were partially offset by lower income taxes due to lower earnings and the impact of effective state tax rates.

Emera Energy

Marketing and trading margin decreased $13 million to $41 million in Q1 2020 compared to $54 million in Q1 2019 as a result of less favourable market conditions, specifically warmer than normal weather, lower natural gas prices and low volatility when compared to 2019.

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LIQUIDITY AND CAPITAL RESOURCES

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

In Q1 2020, the impact of the COVID-19 pandemic and resulting government measures to address this pandemic have resulted in economic slowdowns in all markets served by Emera. Currently, COVID-19 has not had a material financial impact on the Company. Refer to the “Outlook” section for discussion by utility. The impact of COVID-19 may result in decreased cash flow from operations due to the potential of lower sales and slower collection of accounts receivable. The extent of the future impact of COVID-19 on the Company’s operating cash flow cannot be predicted at this time and will depend on future developments, including the duration and severity of the pandemic, further potential government actions and future economic activity and energy usage. 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.

Emera’s future liquidity and capital needs will be predominately for working capital requirements, ongoing rate base investment, business acquisitions, greenfield development, dividends and debt servicing. Emera has a $7.5 billion capital investment plan over the 2020-to-2022 period and the potential for additional capital opportunities of $200 million to $500 million over the forecast period. This plan includes significant rate base investments across the portfolio in renewable and cleaner generation, infrastructure modernization and customer-focused technologies. Capital expenditures at the regulated utilities are subject to regulatory approval. The extent of the future impact of COVID-19 on the profile of the Company’s capital plan cannot be predicted at this time due to reasons discussed earlier. The Company possesses flexibility with respect to its capital investment plan and will continue to monitor current events and related impacts of COVID-19.

Emera plans to use cash from operations, debt raised at the utilities and proceeds from the Emera Maine sale, to support normal operations, repayment of existing debt and capital requirements. Debt raised at certain of the Company’s utilities is subject to applicable regulatory approvals. Equity requirements in support of the Company’s capital investment plan will predominantly be funded in the equity capital markets through the dividend reinvestment plan and the issuance of common and preferred equity. The Company’s future access to capital may be impacted by possible continued COVID-19 related market disruptions. Refer to the “Risk Management and Financial Instruments” section for updated risk disclosure.

As at March 31, 2020, the Company was holding a cash balance of $1.6 billion. Emera also has credit facilities with varying maturities that cumulatively provide $3.8 billion of credit, with approximately $1.3 billion undrawn and available at March 31, 2020. Refer to the “Debt Management” section below for further details. Refer to notes 19 and 20 in the condensed consolidated financial statements for additional information regarding the credit facilities.

As at March 31, 2020, Emera had $155 million CAD ($109 million USD) in receivables related to the expected refund of alternative minimum tax credit carryforwards. Under the provisions of the United States Coronavirus Aid, Relief, and Economic Security (CARES) Act, Emera’s US businesses are allowed to secure their remaining AMT credits in their 2019 filings. The Company has filed for this refund and expects to receive it in 2020.

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Cash Flow from Operating Activities

Net cash provided by operating activities increased $26 million to $428 million for the three months ended March 31, 2020, compared to $402 million for the same period in 2019.

Cash from operations before changes in working capital increased $84 million. The increase was primarily due to higher over-recovery from customers on clause related costs at Tampa Electric.

Changes in working capital decreased operating cash flows by $58 million. The decrease was due to unfavourable changes in cash collateral at Emera Energy and NSPI. This was partially offset by timing of accounts payable at NSPI and Tampa Electric, and decreased fuel inventory at NSPI.

Cash Flow used in Investing Activities

Net cash provided by investing activities increased $448 million to $746 million for the three months ended March 31, 2020, compared to $298 million for the same period in 2019. In 2020, Emera received proceeds of $1.4 billion on the sale of Emera Maine compared to proceeds of $861 million on dispositions in 2019, primarily from the sale of the NEGG and Bayside facilities. This increase in proceeds was partially offset by higher capital expenditures in Q1 2020.

Capital expenditures for the three months ended March 31, 2020, including AFUDC, were $663 million compared to $561 million for the same period in 2019. Details of the 2020 capital spend by segment are shown below:

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Cash Flow from Financing Activities

Net cash provided by financing activities increased $200 million to $165 million for the three months ended March 31, 2020, compared to net cash used in financing activities of $35 million for the same period in 2019. The increase was due to proceeds from committed credit facilities at Tampa Electric, the 2019 net repayment of Emera’s committed credit facilities and issuance of common shares under Emera’s ATM program. These were partially offset by repayment of debt at TECO Finance.