Exhibit 99.1

Management’s Discussion & Analysis

As at August 10, 2021

Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its subsidiaries and investments during the second quarter and year-to-date of 2021 relative to the same periods in 2020; and its financial position as at June 30, 2021 relative to December 31, 2020. 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 and six months ended June 30, 2021; and the Emera Incorporated annual MD&A and 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 June 30, 2021, Emera’s rate-regulated subsidiaries and investments include:

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

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

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 safely delivering cleaner, affordable and reliable energy to its customers.

Emera’s investment in rate-regulated businesses is concentrated in Florida and Nova Scotia. These service areas have generally experienced stable regulatory policies and economic conditions. Emera’s portfolio of regulated utilities provides reliable earnings, cash flow and dividends. Earnings opportunities in regulated utilities are generally driven by the magnitude of net investment in the utility (known as “rate base”), and the amount of equity in the capital structure and the 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 2023. The capital investment plan continues to include significant investments across the portfolio in renewable and cleaner generation, reliability and integrity investments, infrastructure modernization and customer-focused technologies. Emera’s capital investment plan is being funded primarily through internally generated cash flows and debt raised at the operating company level. Equity requirements in support of the Company’s capital investment plan are expected to be funded through the issuance of preferred equity and the issuance of common equity through Emera’s dividend reinvestment plan and at-the-market program. Maintaining investment-grade credit ratings is a priority of management.

Emera has provided annual dividend growth guidance of four to five per cent through 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 of these trends. Emera’s strategy is to fund investments in renewable energy and technology assets which protect the environment and benefit customers through fuel or operating cost savings.

For example, significant investments to facilitate the use of renewable and low-carbon energy include the Maritime Link in Atlantic Canada, the ongoing construction of solar generation 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 dioxide emissions by 2050.

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

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

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”, “Financial Highlights – Other Electric”, and the “Financial Highlights – Other” sections.

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. For further details related to the sale of Emera Maine, refer to the “Significant Items Affecting Earnings” section. While the gain on sale has been excluded from adjusted earnings, earnings for the Other Electric Utilities segment includes earnings from Emera Maine up to the date of its sale on March 24, 2020.

In 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” and “Financial Highlights – Other” sections.

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The following reconciles reported net income (loss) attributable to common shareholders to adjusted net income attributable to common shareholders; and reported earnings (loss) 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 adjustments, the gain on sale of Emera Maine and impairment charges.

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 (loss) 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 (loss) to EBITDA and Adjusted EBITDA:

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

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CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Earnings

Earnings Impact of After-Tax MTM Losses

After-tax MTM losses increased $109 million to $154 million in Q2 2021, compared to $45 million in Q2 2020. Year-to-date, after-tax MTM losses increased $111 million to $124 million compared to $13 million for the same period in 2020. The increase in both periods is due to changes in existing positions at Emera Energy and increased foreign exchange losses on cash flow hedges, partially offset by lower amortization of gas transportation assets in 2021 at Emera Energy.

2020 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). In Q1 2020, a gain on sale of $321 million after tax ($1.31 per common share), net of transaction costs, was recognized. In Q2 2020, an adjustment of $12 million after tax was recognized as a result of finalizing the gain calculation, such that the final year-to-date gain on sale was $309 million after tax ($1.26 per common share).

In addition, impairment charges of $3 million after tax in Q2 2020 and $26 million after tax year-to-date in 2020 were recognized on certain other assets.

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The following table highlights significant changes in adjusted net income attributable to common shareholders from 2020 to 2021.

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

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

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Operating Revenues

For the second quarter of 2021, operating revenues decreased $32 million compared to the second quarter in 2020. Absent increased MTM losses of $124 million, operating revenues increased $92 million due to:

Year-to-date in 2021, operating revenues decreased $57 million compared to the same period in 2020. Absent increased MTM losses of $144 million, operating revenues increased by $87 million due to:

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These impacts were partially offset by:

Operating Expenses

For the second quarter of 2021, operating expenses increased $124 million compared to the second quarter of 2020. Absent the 2020 impairment charges of $3 million, operating expenses increased $127 million due to:

Year-to-date in 2021, operating expenses increased $61 million compared to the same period of 2020. Absent the 2020 impairment charges of $26 million, operating expenses increased $87 million due to:

These impacts were partially offset by:

Other Income, Net

Other income, net decreased year-to-date in 2021 compared to the same period in 2020 primarily due to the 2020 pre-tax gain on sale of Emera Maine.

Interest Expense, Net

Interest expense, net was lower for the second quarter and year-to-date 2021, compared to the same periods in 2020, due to the impact of a stronger CAD, the repayment of corporate debt and lower interest rates.

Income Tax Expense (Recovery)

The increase in income tax recovery for the second quarter in 2021, compared to the same period in 2020 , was primarily due to decreased income before provision for income taxes. The decrease in income tax expense year-to-date in 2021, compared to the same period in 2020, was primarily due to the gain on sale of Emera Maine.

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Net Income and Adjusted Net Income Attributable to Common Shareholders

For the second quarter of 2021, the decrease in net income attributable to common shareholders compared to the same period in 2020, was unfavourably impacted by the $109 million increase in after-tax MTM losses primarily related to Emera Energy, favourably impacted by the $12 million adjustment to the after-tax gain on sale of Emera Maine in Q2 2020 and favourably impacted by the $3 million after-tax impairment charge in 2020. Absent the unfavourable MTM changes, the Q2 2020 adjustment to the gain on sale of Emera Maine and the 2020 impairment charges, adjusted net income attributable to common shareholders increased $19 million. The increase was primarily due to the timing of the preferred dividend declaration in Q2 2020, lower corporate interest expense, and increased earnings contributions from EES and PGS. These were partially offset by the impact of a stronger CAD and lower earnings contributions from Tampa Electric.

Year-to-date in 2021, net income attributable to common shareholders compared to the same period in 2020, was unfavourably impacted by the $309 million after-tax gain on sale of Emera Maine in 2020, unfavourably impacted by the $111 million increase in after-tax MTM losses primarily related to Emera Energy, and favourably impacted by the $26 million after-tax impairment charge in 2020. Absent the net gain on sale of Emera Maine in 2020, the unfavourable MTM changes and the 2020 impairment charges, adjusted net income attributable to common shareholders increased $69 million. The increase was primarily due to higher earnings contribution from EES and PGS, lower corporate interest expense, the 2020 revaluation of deferred taxes due to a reduction in the Nova Scotia corporate income tax rate, lower corporate OM&G, and the timing of preferred dividend declaration in Q2 2020. The increase was partially offset by the impact of a stronger CAD, the 2020 recognition of a corporate income tax recovery previously deferred as a regulatory liability in 2018 at BLPC, and lower earnings due to the sale of Emera Maine in Q1 2020.

Earnings and Adjusted Earnings per Common Share – Basic

Earnings per common share – basic was lower for the second quarter and year-to-date in 2021 due to the decreased earnings as discussed above and the impact of the increase in weighted average shares outstanding.

Adjusted earnings per common share was higher for the second quarter and year-to-date in 2021 due to increased adjusted earnings as discussed above, partially offset by the impact of the increase in the weighted average common 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 CAD for financial reporting. Changes in translation rates, particularly in the value of the USD against the CAD, can positively or adversely affect results.

In general, Emera’s earnings benefit from a weakening CAD and are adversely impacted by a strengthening CAD. The impact 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.

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Results of foreign operations are translated at the weighted average rate of exchange and assets and liabilities of foreign operations are translated at period end rates. The relevant CAD/USD exchange rates for 2021 and 2020 are as follows:

Strengthening of the CAD decreased the net loss by $2 million and decreased adjusted earnings by $11 million in Q2 2021 compared to Q2 2020. The strengthening of the CAD decreased earnings by $9 million and adjusted earnings by $20 million year-to-date in 2021, compared to the same period in 2020.

Consistent with the Company’s risk management policies, Emera partially manages currency risks through matching US denominated debt to finance its US operations and uses 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 USD currency.

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

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

BUSINESS OVERVIEW AND OUTLOOK

COVID-19 Pandemic

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

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

The extent of the future impact of COVID-19 on the Company’s financial results and business operations cannot be predicted at this time but is not expected to have a material financial impact in 2021. Future impacts will depend on a variety of factors, including the duration and severity of the pandemic, timing and effectiveness of vaccinations, further government actions and future economic activity and energy usage. For further information on the potential future impacts of COVID-19 on Emera and its businesses, refer to the “Business Overview and Outlook” and “Liquidity and Capital Resources” sections in the Company’s 2020 annual MD&A.

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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.

Refer to the outlook sections below, by segment, for affiliate specific impacts, if applicable.

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.

Due to continued growth in rate base, Tampa Electric anticipates earning near the bottom of the allowed ROE range in 2021. Tampa Electric sales volumes are expected to be similar to 2020, which benefited from weather that was warmer than in recent years. As a result, Tampa Electric anticipates earnings to be slightly lower than in 2020, which included the impact of a $16 million USD intangible software amortization credit due to a regulatory agreement approved by the FPSC in 2020. Tampa Electric expects customer growth rates in 2021 to be consistent with 2020, reflective of current expected economic growth in Florida.

On August 6, 2021, Tampa Electric filed with the FPSC a joint motion for approval of a settlement agreement (the “Settlement Agreement”) by Tampa Electric and the intervenors in relation to its rate case filed with the FPSC in April 2021. The Settlement Agreement provides for a projected increase of $191 million USD in rates annually, effective with January 2022 bills. This increase will consist of $123 million USD in base rate charges and $68 million USD to recover the costs of retiring assets including, Big Bend coal generation assets Units 1 through 3 and meter assets. The Settlement Agreement further includes two subsequent year adjustments of $90 million USD and $21 million USD, effective January 2023 and January 2024, respectively related to the recovery of future investments in the Big Bend Modernization project and solar generation. The allowed equity in the capital structure will continue to be 54 per cent from investor sources of capital. The Settlement Agreement includes an allowed regulated ROE range of 9.0 per cent to 11.0 per cent with a 9.95 per cent midpoint. It also provides for a 25 basis point increase in the allowed ROE range and mid-point, and $10 million USD of additional revenue, if U.S. Treasury Bond yields exceed a specific threshold set on the date the FPSC votes to approve the agreement. Under the agreement, base rates will not further change from January 1, 2022 through December 31, 2024, unless Tampa Electric’s earned ROE were to fall below the bottom of the range during that time. The Settlement Agreement contains a provision whereby Tampa Electric agrees to quantify the future impact of a change in tax rates on net operating income through a reduction or increase in base revenues within 180 days of when such tax change becomes law or its effective date. The Settlement Agreement will not become effective until approved by the FPSC. The FPSC is expected to consider the matter by October 2021.

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

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

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Canadian Electric Utilities

Canadian Electric Utilities includes NSPI and Emera Newfoundland & Labrador Holdings Inc. (“ENL”). NSPI is a vertically integrated regulated electric utility engaged in the generation, transmission and distribution of electricity and is 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 anticipates earning near the low end of its allowed ROE range in 2021 and expects rate base and earnings to be higher than 2020. Assuming normal weather and a modest economic recovery from impacts of the COVID-19 pandemic in 2021, NSPI expects sales volumes to be higher than 2020.

In Q1 2021, NSPI received its 2021 granted emissions allowances under the Nova Scotia Cap-and-Trade Program Regulations. These 2021 allowances will be used in 2021 or allocated within the initial four-year compliance period that ends in 2022. With the forthcoming Nova Scotia block (“NS Block”), which is described below, NSPI is on track to meet the requirements of the program, where compliance is forecasted to be achieved through the granted emissions allowances, reduced emissions and credit purchases under the Cap-and-Trade 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.

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 (“Muskrat Falls”). Nalcor Energy (“Nalcor”) has agreed to commence delivery of the NS Block by August 15, 2021 which will provide NSPI with approximately 900 GWh of energy annually over 35 years. In addition, for the first five years of the NS Block, NSPI is also entitled to receive approximately 240 GWh of additional energy from the Supplemental Energy Block transmitted through the Maritime Link. NSPI has the option of purchasing additional market-priced energy from Nalcor through the Energy Access Agreement. Pursuant to the agreement, Nalcor is obligated to offer NSPI a minimum average of 1.2 TWh of energy annually. Nalcor continues to work toward construction completion and final commissioning of the Lower Churchill projects (including Muskrat Falls and LIL) in the second half of 2021.

Under the provincially legislated Renewable Energy Regulations, 40 per cent of electric sales must be generated from renewable sources. Due to the delay of the NS Block, the provincial government provided NSPI with an alternative compliance plan in 2020, as permitted by the legislation. The alternative compliance plan requires NSPI to supply customers with at least 40 per cent of energy generated from renewable sources over the 2020 to 2022 period. NSPI expects to achieve this alternative compliance standard.

In 2021, capital investment for NSPI is expected to be approximately $395 million (2020 – $316 million), including AFUDC, primarily in capital projects required to support system reliability and hydroelectric infrastructure renewal projects.

ENL

Equity earnings from NSPML and LIL are expected to be higher in 2021, compared to 2020. Both the NSPML and LIL investments are recorded as “Investments subject to significant influence” on Emera’s Condensed Consolidated Balance Sheets.

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NSPML

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

The Maritime Link assets entered service on January 15, 2018 and provide for the transmission of energy between Newfoundland and Nova Scotia, improved reliability and ancillary benefits, supporting the efficiency and reliability of energy in both provinces. The Maritime Link will transmit at greater capacity when the Lower Churchill project is complete.

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

Two of four generators at Muskrat Falls are completed and available for service, the first in Q3 2020 and the second in Q2 2021. The third unit is expected to be completed in Q3 2021. Nalcor continues to work toward final project commissioning of Muskrat Falls and LIL in the second half of 2021. Nalcor has agreed to commence delivery of the NS Block by August 15, 2021 and the NS Block will be delivered over the next 35 years pursuant to the agreements. On August 9, 2021, NSPML filed a final capital cost application with the UARB seeking approval to recover capital costs associated with the Maritime Link and requesting to set rates for 2022. A decision by the UARB is expected in early 2022.

In 2021, NSPML expects to invest approximately $10 million (2020 - $7 million) in capital.

LIL

ENL is a limited partner with Nalcor in LIL. Construction of the LIL is complete and Nalcor continues to work toward final project commissioning in 2021.

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 $655 million, comprised of $410 million in equity contribution and $245 million of accumulated equity earnings. Emera’s total equity contribution in the LIL, excluding accumulated equity earnings, is estimated to be approximately $650 million after the Lower Churchill projects are completed.

Cash earnings and return of equity will begin after commissioning of the LIL by Nalcor, and until that point Emera will continue to record AFUDC earnings. Nalcor continues to work toward final project commissioning of the LIL in the second half of 2021.

Other Electric Utilities

Other Electric Utilities includes Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities. ECI’s regulated utilities include vertically integrated regulated electric utilities of BLPC on the island of Barbados, GBPC on Grand Bahama Island, 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 was included in the Other Electric Utilities segment in Q1 2020.

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Removing the Q1 2020 earnings contribution from Emera Maine and the Q1 2020 recognition of a $10 million previously deferred corporate income tax recovery, Other Electric Utilities’ earnings in 2021 are expected to increase over the prior year.

In Q1 2021, GBPC notified the GBPA of its intention to submit a Rate Plan proposal in 2021.

On November 6, 2020, BLPC notified the FTC that it plans to file a general rate review application with the FTC. This application is expected to be filed in the second half of 2021.

In 2021, capital investment in the Other Electric Utilities segment is expected to be approximately $120 million USD (2020 – $111 million USD including $14 million USD invested in Emera Maine projects), primarily in more efficient and cleaner sources of generation, including renewables and battery storage. BLPC expects to complete installation of a 33 MW diesel engine plant in the second half of 2021. This 33 MW plant is expected to increase efficiency and bridge BLPC’s transition to increased renewable sources of generation.

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.

Gas Utilities and Infrastructure earnings are anticipated to be higher in 2021 than 2020 primarily due to approved base rate increases for PGS and NMGC.

PGS anticipates earning within its allowed ROE range in 2021 and expects rate base and earnings to be higher than in 2020. PGS expects customer growth in 2021 to be higher than Florida’s population growth rates, reflecting expectations of continued strong housing demand in Florida and commercial activity trending back towards normal levels. PGS sales volumes are expected to increase above customer growth, as the COVID-19 pandemic impact on 2021 commercial energy sales is expected to be less than 2020. In January 2021, a base rate increase went into effect in accordance with the FPSC approved rate case settlement and is expected to result in a $34 million USD revenue increase.

NMGC’s application for new rates was approved in December 2020 and took effect in January 2021. The new rates result in an increase in revenue of approximately $5 million USD annually. NMGC anticipates earning at or near its authorized ROE in 2021 and expects rate base to be higher than 2020. NMGC expects customer growth rates to be consistent with historical trends.

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

In 2021, capital investment in the Gas Utilities and Infrastructure segment is expected to be approximately $430 million USD (2020 - $553 million USD), including AFUDC. PGS will make investments to expand its system and support customer growth. NMGC completed the Santa Fe Mainline Looping project in 2021 and will continue to invest in system improvements.

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Other

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

Business operations in the Other segment include Emera Energy and Emera Technologies LLC (“ETL”). Emera Energy consists of EES, a wholly owned physical energy marketing and trading business and an equity investment in a 50.0 per cent joint venture ownership of Bear Swamp, a 600 MW pumped storage hydroelectric facility in northwestern Massachusetts. ETL is a wholly owned technology company focused on finding ways to deliver renewable and resilient energy to customers.

Corporate items included in the Other segment are certain corporate-wide functions including executive management, strategic planning, treasury services, legal, financial reporting, tax planning, corporate business development, corporate governance, investor relations, risk management, insurance, acquisition and disposition related costs, gains or losses on select assets sales, and corporate human resource activities. It includes interest revenue on intercompany financings 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 natural gas and electricity markets, which can be influenced by weather, local supply constraints and other supply and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1 and Q4 usually providing the greatest opportunity for earnings. EES is generally expected to deliver annual adjusted net earnings of $15 to $30 million USD ($45 to $70 million USD of margin), with the opportunity for upside when market conditions present.

Absent the gain on the TECO Guatemala Holdings award in Q4 2020, the adjusted net loss from the Other segment is expected to be lower in 2021, primarily due to decreased interest expense, lower OM&G and higher earnings from EES. The decrease is expected to be partially offset by increased taxes due to a lower net loss and increased project spend in ETL.

In 2021, capital investment in the Other segment is expected to be approximately $5 million (2020 - $3 million).

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DEVELOPMENTS

Tampa Electric Rate Case Settlement Agreement

On August 6, 2021, Tampa Electric filed with the FPSC a joint motion for approval of a Settlement Agreement by Tampa Electric and the intervenors in relation to its rate case filed with the FPSC in April 2021. The Settlement Agreement provides for a projected increase of $191 million USD in rates annually, effective with January 2022 bills. This increase will consist of $123 million USD in base rate charges and $68 million USD to recover the costs of retiring assets including, Big Bend coal generation assets Units 1 through 3 and meter assets. The Settlement Agreement further includes two subsequent year adjustments of $90 million USD and $21 million USD, effective January 2023 and January 2024, respectively related to the recovery of future investments in the Big Bend Modernization project and solar generation. The allowed equity in the capital structure will continue to be 54 per cent from investor sources of capital. The Settlement Agreement includes an allowed regulated ROE range of 9.0 per cent to 11.0 per cent with a 9.95 per cent midpoint. The Settlement Agreement will not become effective until approved by the FPSC. The FPSC is expected to consider the matter by October 2021. For further information on the Settlement Agreement, refer to the “Business Overview and Outlook – Florida Electric Utility” section.

Delivery of NS Block

Nalcor has agreed to commence delivery of the NS Block by August 15, 2021 which will be delivered over the next 35 years pursuant to the agreements. On August 9, 2021, NSPML filed a final capital cost application with the UARB seeking approval to recover capital costs associated with the Maritime Link and requesting to set rates for 2022. A decision by the UARB is expected in early 2022. For further information on the NS Block, refer to the “Business Overview and Outlook – Canadian Electric Utilities” and “Contractual Obligations” sections.

Preferred Shares

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

Appointments

Board of Directors

Effective August 10, 2021, Gil C. Quiniones joined the Emera Board of Directors. Mr. Quiniones is the President and Chief Executive Officer of the New York Power Authority, the largest state public power organization in the United States, operating 16 generating facilities and more than 2,200 kilometres of transmission lines.

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(1) In 2020, 4,544,025 common shares were issued under Emera’s at-the-market program (“ATM program”) at an average price of $56.04 per share for gross proceeds of $255 million ($251 million net of issuance costs).

(2) In Q2 2021, 1,396,926 common shares were issued under Emera’s ATM program at an average price of $56.95 per share for gross proceeds of $80 million ($78 million net of issuance costs). For the six months ended June 30, 2021, 2,337,026 common shares were issued under Emera’s ATM program at an average price of $55.59 per share for gross proceeds of $130 million ($128 million net of issuance costs). As at June 30, 2021, an aggregate gross sales limit of $115 million remained available for issuance under the ATM program. Emera’s ATM program automatically terminated on July 14, 2021. Refer to below for more information.

As at August 6, 2021 the amount of issued and outstanding common shares was 256.5 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 June 30, 2021 was 255.8 million (2020 – 246.7 million) and for the six months ended June 30, 2021 was 254.6 million (2020 – 245.7 million).

ATM Equity Program

Emera’s ATM Program automatically terminated on July 14, 2021 with the expiry of the Company’s short-form base shelf prospectus dated June 14, 2019. Emera intends to establish a new ATM Program during Q3 2021.

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Florida Electric Utility’s CAD contribution to consolidated net income decreased $21 million to $125 million in Q2 2021, compared to $146 million in Q2 2020. Year-to-date in 2021, the CAD contribution to consolidated net income decreased $17 million to $208 million compared to $225 million for the same period in 2020. Decreases in both periods were due to the impact of the strengthening CAD, higher depreciation and amortization expense reflecting increased capital investment and a 2020 regulatory settlement, and higher OM&G expense. These decreases were partially offset by higher AFUDC earnings.

The impact of the strengthening Canadian dollar decreased CAD earnings for the three and six months ended June 30, 2021 by $16 million and $21 million, respectively.

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Operating Revenues – Regulated Electric

Electric revenues increased $78 million to $532 million in Q2 2021, compared to $454 million in Q2 2020. Year-to-date in 2021, electric revenues increased $104 million to $979 million, compared to $875 million for the same period in 2020. Increases in both periods were due to higher fuel recovery clause revenue as a result of higher fuel costs.

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

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power increased $63 million to $156 million in Q2 2021, compared to $93 million in Q2 2020 and year-to-date, increased $85 million to $284 million in 2021, compared to $199 million in the same period in 2020. The increase in both periods was primarily due to increased natural gas prices.

Average fuel cost per MWh increased in Q2 2021 and year-to-date compared to the same periods in 2020, primarily due to increased natural gas prices.

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(1) Regulated fuel for generation and purchased power includes NSPI’s Fuel Adjustment Mechanism (“FAM”) and fixed cost deferrals on the Condensed Consolidated Statements of Income; however, it is excluded in the segment overview.

Canadian Electric Utilities’ contribution is summarized in the following table:

Canadian Electric Utilities’ contribution to consolidated net income increased $7 million to $44 million in Q2 2021, compared to $37 million in Q2 2020 and year-to-date increased $3 million to $132 million compared to $129 million in 2020. Increases in both periods were primarily driven by higher contribution from NSPI. This was a result of lower FAM and fixed cost deferrals. These increases were partially offset by lower Maritime Link assessment included in revenue compared to 2020 and higher depreciation and amortization due to increased property plant and equipment.

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NSPI

Operating Revenues – Regulated Electric

Operating revenues increased $6 million to $341 million in Q2 2021, compared to $335 million in Q2 2020 due to increased customer driven sales volumes and fuel-related pricing, partially offset by weather driven impacts on sales volumes and lower Maritime Link assessment included in revenue compared to 2020.

Year-to-date in 2021, operating revenues decreased $9 million to $784 million compared to $793 million for the same period in 2020 due to lower Maritime Link assessment included in revenue and weather driven impacts on sales volumes, partially offset by increased customer driven sales volumes and fuel-relating pricing.

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

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power increased $27 million to $173 million in Q2 2021, compared to $146 million in Q2 2020, and year-to-date increased $45 million to $385 million, compared to $340 million in the same period in 2020. Increases in both periods were due to changes in generation mix and higher Maritime Link assessment costs. Year-over-year, higher commodity prices also contributed to the increase.

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Average fuel cost per MWh increased in Q2 2021 and year-to-date, compared to the same periods in 2020. This was primarily due to changes in generation mix driven by emissions constraints, with increased generation from lower carbon intensity sources such as IPP, import, and biomass generation offsetting decreased generation from solid fuel, and natural gas. Higher Maritime Link assessment costs also contributed to a higher average fuel cost. Increased commodity prices contributed to a higher average fuel cost year-over-year.

NSPI’s FAM regulatory balance increased $45 million from a regulatory liability of $21 million at December 31, 2020 to a regulatory asset of $24 million at June 30, 2021 primarily due to under-recovery of current period fuel costs.

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Electric sales volumes were 306 GWh in Q2 2021 compared to 290 GWh in Q2 2020. Year-to-date, electric sales volumes were 595 GWh compared to 601 GWh for the same period in 2020.

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power increased $17 million to $44 million in Q2 2021, compared to $27 million in Q2 2020 due to higher oil prices at BLPC. Year-to-date in 2021, regulated fuel for generation and purchased power was $77 million, consistent with the same period in 2020, due to higher oil prices at BLPC offset by transmission pool expense at Emera Maine in 2020.

 (1) Operating revenues – regulated gas includes $12 million of finance income from Brunswick Pipeline (2020 - $11 million) for the three months ended June 30, 2021 and $23 million (2020 - $22 million) for the six months ended June 30, 2021; however, it is excluded from the gas revenues analysis below.

Gas Utilities and Infrastructure’s contribution is summarized in the following table:

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Gas Utilities and Infrastructure’s CAD contribution to consolidated net income increased $7 million to $34 million in Q2 2021, compared to $27 million in Q2 2020 and year-to-date increased $17 million to $114 million, compared to $97 million in 2020. The increase in both periods was due to PGS’s higher base revenues as the result of a base rate increase and customer growth.

The impact of the change in the foreign exchange rate decreased CAD earnings for the three months ended June 30, 2021 and year-to-date 2021 by $4 million and $8 million respectively.

Operating Revenues – Regulated Gas

Gas Utilities and Infrastructure’s operating revenues increased $48 million to $198 million in Q2 2021, compared to $150 million in Q2 2020 and year-to-date increased $110 million to $510 million, compared to $400 million in the same period in 2020. The increase in both periods was due to a base rate increase at PGS and NMGC effective January 1, 2021, customer growth at PGS, and higher purchased gas adjustment clause revenues at PGS and NMGC as a result of higher gas prices.

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

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Regulated Cost of Natural Gas

Regulated cost of natural gas increased $25 million to $55 million in Q2 2021, compared to $30 million in Q2 2020 and year-to-date increased $68 million to $179 million in Q2 2021, compared to $111 million in the same period in 2020. The increase in both periods was due to higher gas prices at PGS and NMGC.

Gas sales by type are summarized in the following table:

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

(2) Marketing and trading margin excludes a pre-tax MTM loss of $205 million in Q2 2021 (2020 - $87 million loss) and a loss of $167 million year-to-date (2020 – $24 million loss).

Other’s adjusted contribution is summarized in the following table:

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Emera Energy

Marketing and trading margin increased $13 million to nil in Q2 2021, compared to a loss of $13 million in Q2 2020 due to the favourable impact of weather in several key market areas, which resulted in higher market prices and volatility that led to higher natural gas margins.

Year-to-date, margin increased $39 million to $67 million in 2021, compared to $28 million for the same period in 2020. In addition to the Q2 2021 differential noted above, this increase reflected the mid-February extreme weather event across the South-Central US which sharply increased pricing and volatility in adjacent markets where Emera Energy has a presence, such that the business was able to capitalize. The Northeast, though seasonally cold, was largely insulated from the weather event, but still provided steady opportunity throughout Q1.

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