Form 6-K EMERA INC For: Aug 11

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER

PURSUANT TO RULE 13a-16 OR 15d-16

UNDER THE SECURITIES EXCHANGE ACT OF 1934

For the month of August, 2022

Commission File Number: 000-54516

Emera Incorporated

(Exact name of registrant as specified in its charter)

5151 Terminal Road

Halifax NS B3J 1A1

Canada

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F ☐                Form 40-F ☑

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ☐

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ☐

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

EXHIBIT INDEX

Exhibit 99.1

Management’s Discussion & Analysis

As at August 9, 2022

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 2022 relative to the same periods in 2021; and its financial position as at June 30, 2022 relative to December 31, 2021. 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, Gas Utilities and Infrastructure, Other Electric Utilities, 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, 2022; and the Emera Incorporated annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2021. 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, 2022, Emera’s rate-regulated subsidiaries and investments include:

All amounts are in Canadian dollars (“CAD”), except for the Florida Electric Utility, Gas Utilities and Infrastructure, and Other Electric Utilities 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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TABLE OF CONTENTS

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 investments; expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; maintenance of adequate insurance coverage; changes in customer energy usage patterns; developments in technology that could reduce demand for electricity; global climate change; weather; 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.

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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 electric and gas services in designated territories under franchises and are overseen by regulatory authorities. Emera’s strategic focus continues to be safely delivering cleaner, affordable and reliable energy to its customers.

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

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

Emera has provided annual dividend growth guidance of four to five per cent through 2024. The Company targets a long-term dividend payout ratio of adjusted net income of 70 to 75 per cent and, while the payout ratio is likely to exceed that target through and beyond the forecast period, it is expected to return to that range over time. For further information on the non-GAAP measure “Dividend Payout Ratio of Adjusted Net Income”, refer to the “Non-GAAP Financial Measures and Ratios” section.

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 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.

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

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

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

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

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

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

NON-GAAP FINANCIAL MEASURES AND RATIOS

Emera uses financial measures and ratios 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 and ratios by adjusting certain GAAP measures for specific items. Management believes excluding these items better distinguishes the ongoing operations of the business and allows investors to better understand and evaluate the business. These measures and ratios are discussed and reconciled below.

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Adjusted Net Income Attributable to Common Shareholders, Adjusted Earnings Per Common Share – Basic and Dividend Payout Ratio of Adjusted Net Income.

Emera calculates an adjusted net income attributable to common shareholders (“adjusted net income”) measure by excluding the effect of mark-to-market (“MTM”) adjustments and the impact of the NSPML unrecoverable costs.

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 excludes these MTM adjustments for evaluation of performance and incentive compensation. The MTM adjustments are related to the following:

For further detail on MTM adjustments, refer to the “Consolidated Financial Review”, “Financial Highlights – Other Electric Utilities”, and “Financial Highlights – Other” sections.

In February 2022, the UARB issued a decision to disallow the recovery of $9 million in costs ($7 million after-tax) included in NSPML’s final capital cost application. The after-tax unrecoverable costs were recognized in “Income from equity investments” in Emera’s Condensed Consolidated Statements of Income. Management believes excluding these unrecoverable costs from the calculation of adjusted net income better reflects the underlying operations in the period. For further details on the NSPML unrecoverable costs, refer to the “Business Overview and Outlook – Canadian Electric Utilities” and “Financial Highlights – Canadian Electric Utilities” sections.

Adjusted earnings per common share – basic and dividend payout ratio of adjusted net income are non-GAAP ratios which are calculated using adjusted net income, as described above.

Emera calculates adjusted net income and adjusted earnings per common share – basic for the Canadian Electric Utilities, Other Electric Utilities, and Other segments. Reconciliation to the nearest GAAP measure is included in each segment. Refer to “Financial Highlights – Canadian Electric Utilities”, “Financial Highlights – Other Electric Utilities” and “Financial Highlights – Other” sections. For further details on dividend payout ratio of adjusted net income, see the “Dividend Payout Ratio” section in Emera’s 2021 annual MD&A.

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The following reconciles net income (loss) attributable to common shareholders to adjusted net income:

(1) Net of income tax recovery of $91 million for the three months ended June 30, 2022 (2021- $62 million recovery) and $37 million recovery for the six months ended June 30, 2022 (2021- $49 million recovery).

(2) Emera accounts for NSPML as an equity investment and therefore the after-tax unrecoverable costs were recorded in “Income from equity investments” on Emera’s Condensed Consolidated Statements of Income.

EBITDA and Adjusted EBITDA

Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) and adjusted EBITDA are non-GAAP financial measures used by Emera. These financial measures are 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.

Similar to adjusted net income calculations described above, adjusted EBITDA represents EBITDA absent the income effect of MTM adjustments and the NSPML unrecoverable costs.

The following is a reconciliation of net income (loss) to EBITDA and Adjusted EBITDA:

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

(2) Emera accounts for NSPML as an equity investment and therefore the after-tax unrecoverable costs were recorded in “Income from equity investments” on Emera’s Condensed Consolidated Statements of Income.

CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Earnings

Earnings Impact of MTM Loss, After-Tax

MTM loss, after-tax increased $69 million to $223 million in Q2 2022, compared to $154 million in Q2 2021 primarily due to higher amortization of gas transportation assets in 2022 and changes in existing positions at Emera Energy. Year-to-date, MTM loss, after-tax decreased $28 million to $96 million compared to $124 million for the same period in 2021 due to a larger reversal of MTM losses in 2022, partially offset by higher amortization of gas transportation assets and changes in existing positions in 2022 at Emera Energy.

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Consolidated Financial Highlights

The following table highlights significant changes in adjusted net income from 2021 to 2022:

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

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Consolidated Income Statement Highlights

(1) Effective February 10, 2022, deferred share units are no longer able to be settled in shares and are therefore excluded from weighted average shares of common stock outstanding.

Operating Revenues

For Q2 2022, operating revenues increased $243 million compared to Q2 2021 and, absent increased MTM losses of $99 million, increased $342 million. Year-to-date 2022, operating revenues increased $646 million compared to 2021 and, absent decreased MTM losses of $43 million, increased by $603 million. The increases in both periods were due to higher fuel cost recoveries at NMGC, Tampa Electric, PGS, and BLPC, new rates effective January 2022, favourable weather and customer growth at Tampa Electric, and increased sales volumes at NSPI. These increases were partially offset by decreased marketing and trading margin at EES reflecting 2021’s Winter Storm Uri, which resulted in incremental margin.

Operating Expenses

For Q2 2022, operating expenses increased $282 million and year-to-date 2022, increased $543 million compared to the same periods in 2021. The increases in both periods were due to higher natural gas and fuel prices at the regulated utilities and increased OM&G at Tampa Electric, NSPI and Corporate.

Net Income and Adjusted Net Income

For Q2 2022, net income attributable to common shareholders compared to Q2 2021, was unfavourably impacted by the $69 million increase in after-tax MTM losses. Absent the unfavourable MTM changes, adjusted net income increased $19 million. The increase was primarily due to higher earnings contribution from Tampa Electric, partially offset by realized gains on Corporate cash flow hedges in 2021.

Year-to-date in 2022, net income attributable to common shareholders, compared to the same period in 2021, was favourably impacted by the $28 million decrease in after-tax MTM losses and unfavourably impacted by the $7 million in NSPML unrecoverable costs. Absent these changes, adjusted net income increased $18 million. The increase was primarily due to higher earnings contributions from Tampa Electric and NSPI. These were partially offset by increased Corporate OM&G due to the timing of long-term compensation and related hedges, lower earnings contribution from EES, realized gains on Corporate cash flow hedges in 2021, and increased preferred stock dividends due to issuance of preferred shares in 2021.

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Earnings and Adjusted Earnings per Common Share – Basic

Earnings per common share – basic were lower for Q2 2022, compared to Q2 2021, due to the impact of lower earnings as discussed above and the impact of the increase in weighted average shares of common stock outstanding. Earnings per common share – basic year-to-date in 2022 were higher due to increased adjusted earnings as discussed above, partially offset by the impact of the increase in weighted average shares outstanding.

Adjusted earnings per common share were higher for Q2 2022 and year-to-date 2022, due to increased earnings as discussed above, partially offset by the impact of the increase in weighted average shares of common stock outstanding.

Effect of Foreign Currency Translation

Emera operates in Canada, the United States and various Caribbean countries and, as such, 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 in any period is driven by rate changes, the timing and percentage of earnings from foreign operations, and the impact of entered foreign exchange cash flow hedges 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/USD exchange rates for 2022 and 2021 are as follows:

The table below includes Emera’s significant segments whose contributions to adjusted net income 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

(3) Net of $173 million MTM loss, after-tax for the three months ended June 30, 2022 (2021- $119 million) and $70 million MTM loss, after-tax for the six months ended June 30, 2022 (2021- $96 million).

The impact of changes in the foreign exchange rate on net income in Q2 and year-to-date in 2022 was minimal. The weakening of the CAD increased adjusted net income by $7 million in Q2 and year-to-date in 2022 (including the current quarter and year-to-date impacts of foreign exchange hedges in the Other segment), compared to the same period in 2021.

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BUSINESS OVERVIEW AND OUTLOOK

COVID-19 Pandemic

The Company’s priorities continue to be 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 has had varying effects on the service territories in which Emera operates, on a consolidated basis, COVID-19 is not expected to have a material financial impact in 2022. For further information on COVID-19 and its potential future impacts on Emera and its businesses, refer to the “Business Overview and Outlook” and “Liquidity and Capital Resources” sections in Emera’s 2021 annual MD&A.

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 anticipates earning within its ROE range in 2022. New base rates effective January 1, 2022 are expected to result in higher 2022 USD earnings than in 2021. Tampa Electric expects customer growth rates in 2022 to be consistent with 2021, reflective of current economic growth in Florida.

Tampa Electric’s 2021 settlement agreement allows the company to request an increase to revenue and ROE due to increases in the 30-year United States Treasury bond yield rate. On July 1, 2022, Tampa Electric requested the FPSC to increase its annual base rates by $10 million USD and to increase its ROE. If approved, the new mid-point ROE will be 10.20 per cent, and the range will be 9.25 per cent to 11.25 per cent. The FPSC is expected to issue a decision in August 2022.

The mid-course fuel adjustment requested by Tampa Electric on January 19, 2022, was approved on March 1, 2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel and capacity costs of $169 million USD and will be spread over customer bills from April 1, 2022 through December 2022.

In 2022, capital investment in the Florida Electric Utility segment is expected to be approximately $1.1 billion USD (2021—$1.2 billion USD), including allowance for funds used during construction (“AFUDC”). Capital projects include continuation of the modernization of the Big Bend Power Station, solar investments, grid modernization, storm hardening investments, and operational infrastructure.

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 within its allowed ROE range in 2022 and expects earnings to be consistent with 2021. Warmer than normal weather adversely affected NSPI’s sales volumes in 2021. NSPI expects sales volumes to be higher than 2021.

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NSPI is currently operating under a three-year fuel stability plan which results in an average annual overall rate increase of 1.5 per cent to recover fuel costs for the period of 2020 through 2022. The 2022 rates include approximately $162 million related to the recovery of Maritime Link costs (discussed below in the “ENL, NSPML” section).

On January 27, 2022, NSPI filed a General Rate Application (“GRA”) with the UARB, which was then amended on February 18, 2022. The GRA proposes a rate stability plan for 2022 through 2024 which includes average base rate increases of 2.8 per cent per year and average fuel rate increases pursuant to the Fuel Adjustment Mechanism (“FAM”) of 0.8 per cent per year on August 1, 2022, January 1, 2023 and January 1, 2024. The proposed rates would result in annualized incremental revenue (base and fuel rates) increases of $52 million in 2022 ($21 million related to August 1, 2022 through December 31, 2022), $54 million in 2023 and $56 million in 2024. The effective timing of any approved increases would be determined by the UARB. The hearing for this matter is scheduled for September 2022 and a decision by the UARB is expected later in the year.

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

In 2022, NSPI expects to invest $565 million (2021 – $388 million), including AFUDC, primarily in capital projects to support system reliability, renew hydroelectric infrastructure, and add renewable capacity.

Environmental Legislation and Regulations

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 compliance will be recoverable under NSPI’s regulatory framework. NSPI faces risks associated with achieving climate-related and environmental legislative requirements, including the risk of non-compliance, which could adversely affect NSPI’s operations and financial performance. For further discussion on these risks and environmental legislation and regulations, refer to the “Enterprise Risk and Risk Management” and “Business Overview and Outlook – Canadian Electric Utilities” sections respectively of Emera’s 2021 annual MD&A. Recent developments related to provincial and federal environmental laws and regulations are outlined below.

Nova Scotia Cap-and-Trade Program Regulations:

In Q1 2022, NSPI received its 2022 granted emissions allowances under the Nova Scotia Cap-and-Trade Program Regulations. These allowances will be allocated within the initial four-year compliance period that ends in 2022. In addition to the granted allowances, NSPI is permitted to purchase up to five per cent of the credits available at provincial auctions or reserve credits, which are anticipated to be priced at a premium, from the provincial government.

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Nova Scotia Renewable Energy Regulations:

The alternative compliance plan, under the provincially legislated Renewable Energy Regulations, requires NSPI to achieve 40 per cent of electric sales generated from renewable sources over the 2020 through 2022 period. With delivery of the NS Block commencing later than anticipated, as well as further interruptions in supply due to delays in the LIL, NSPI is not forecasting the ability to achieve the requirements of the alternative compliance plan. The Renewable Energy Regulations require NSPI to have acted in a duly diligent manner. If NSPI is found not to have acted in a duly diligent manner, it could be subject to a maximum penalty of $10 million.

ENL

Absent the NSPML unrecoverable costs, equity earnings from NSPML and LIL are expected to be consistent in 2022, compared to 2021. Both NSPML and LIL investments are recorded as “Investments subject to significant influence” on Emera’s Condensed Consolidated Balance Sheets.

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 into service on January 15, 2018, enabling the transmission of energy between Newfoundland and Nova Scotia, improved reliability and ancillary benefits, and supporting the efficiency and reliability of energy in both provinces. For further information on the NS Block, refer to the NSPI section above.

On August 3, 2022, NSPML submitted an application to the UARB requesting recovery of approximately $164 million in Maritime Link costs for 2023. A decision is expected in Q4 2022.

In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate base of approximately $1.8 billion less approximately $9 million of costs ($7 million after-tax) that would not otherwise have been recoverable if incurred by NSPI. NSPML also received approval to collect $168 million (2021- $172 million) from NSPI for the recovery of Maritime Link costs in 2022. This is subject to a monthly holdback of up to $2 million from April to December 2022 contingent on receiving at least 90 per cent of NS Block deliveries, including Supplementary Energy deliveries, and the cost of replacement energy.

NSPML does not anticipate any significant capital investment in 2022 (2021 – $6 million).

LIL

ENL is a limited partner with Nalcor in LIL. Construction of the LIL is complete and Nalcor is working towards final commissioning in 2022.

Equity earnings from the LIL investment are based upon the book value of the equity investment and the approved ROE. Emera’s current equity investment is $710 million, comprised of $410 million in equity contribution and $300 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.

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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 an intrastate regulated gas distribution utility engaged in the purchase, transmission, distribution and sale of natural gas serving customers in New Mexico. SeaCoast is a regulated intrastate natural gas transmission company offering services in Florida. Brunswick Pipeline is a regulated 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick, to markets in the northeastern United States.

Gas Utilities and Infrastructure USD earnings are anticipated to be higher in 2022 than 2021, primarily due to customer growth and the reversal of accumulated depreciation at PGS, as discussed below.

PGS anticipates earning within its allowed ROE range in 2022 and expects rate base and USD earnings to be higher than in 2021. PGS expects favourable customer growth in 2022 and residential and commercial sales volumes in 2022 are expected to increase at a level consistent with customer growth. The PGS rate case settlement, which was approved in November 2020, also provides the ability to reverse a total of $34 million USD of accumulated depreciation through 2023. Through June 2022, PGS reversed $10 million USD accumulated depreciation. The reversal of the remaining accumulated depreciation is expected to occur over the 2022 and 2023 periods.

NMGC anticipates earning below its authorized ROE in 2022 and expects rate base to be higher than 2021. NMGC expects customer growth rates to be consistent with historical trends.

On December 13, 2021, NMGC filed a rate case with the NMPRC for new rates to become effective January 2023. On May 20, 2022, NMGC filed an unopposed settlement agreement with the NMPRC for an increase of $19 million USD in annual base revenues. The proposed rates reflect the recovery of increased operating costs and capital investments in pipelines and related infrastructure. A hearing was held in June 2022 and a decision from the NMPRC is expected in Q4 2022.

In 2018, SeaCoast executed a 34-year agreement to provide long-term firm gas transportation service via a 21-mile, 30-inch pipeline lateral. The lease of the pipeline lateral commenced January 1, 2022.

In 2022, capital investment in the Gas Utilities and Infrastructure segment is expected to be approximately $485 million USD (2021 - $407 million USD), including AFUDC. PGS will make investments to expand its system and support customer growth. NMGC will continue to make investments to maintain the reliability of its system.

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, and a 19.5 per cent interest in Lucelec on the island of St. Lucia which is accounted for on the equity basis.

Other Electric Utilities’ USD earnings in 2022 are expected to increase over the prior year due to higher earnings due to higher base rates at GBPC and BLPC and the continued recovery in local economies from the impacts of COVID-19.

On March 31, 2022, Emera completed the sale of its 51.9 per cent interest in Dominica Electricity Services Ltd. (“Domlec”) for proceeds which approximated carrying value. Domlec was included in the Other Electric segment in Q1 2022. The sale did not have a material impact on earnings.

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On January 14, 2022, the GBPA issued its decision on GBPC’s rate application. The approved increase in annual revenues of $3.5 million USD commenced on April 1, 2022.

On October 4, 2021 BLPC submitted a general rate review application to the FTC. The application seeks a rate adjustment and the implementation of a cost reflective rate structure that will facilitate the changes expected in the newly reformed electricity market and the country’s transition towards 100 per cent renewable energy generation. The application seeks recovery of capital investment in plant, equipment and related infrastructure and results in an increase in annual non-fuel revenue of approximately $23 million USD upon approval. The application includes a request for an allowed regulatory ROE of 12.50 per cent on an allowed equity capital structure of 65 per cent. BLPC expects a decision from the FTC and new rates in 2022.

In 2022, capital investment in the Other Electric Utilities segment is expected to be $65 million USD (2021 – $88 million USD), primarily in more efficient and cleaner sources of generation, including renewables and battery storage.

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 633 MW pumped storage hydroelectric facility in northwestern Massachusetts. ETL is a wholly owned technology company focused on finding ways to deliver renewable and resilient energy to customers.

Corporate items included in the Other segment are certain corporate-wide functions including executive management, strategic planning, treasury services, legal, financial reporting, tax planning, corporate business development, corporate governance, investor relations, risk management, insurance, acquisition and disposition related costs, gains or losses on select assets sales, and corporate human resource activities. It includes interest revenue on intercompany financings recorded in “Intercompany revenue” and interest expense on corporate debt in both Canada and the United States. 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 income within its guidance range of $15 to $30 million USD ($45 to $70 million USD of margin).

The adjusted net loss from the Other segment is expected to be higher in 2022 due to higher Corporate OM&G which is primarily driven by the timing of long-term compensation and related hedges, EES returning to its normal earnings range, realized foreign exchange gains on cash flow hedges in 2021, and additional preferred dividends. This is expected to be partially offset by decreased taxes due to a higher net loss.

The Other segment does not anticipate any significant capital investment in 2022 (2021 – $1 million).

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CONSOLIDATED BALANCE SHEET HIGHLIGHTS

Significant changes in the Condensed Consolidated Balance Sheets between December 31, 2021 and June 30, 2022 include:

15

DEVELOPMENTS

Appointments

Effective July 1, 2022, Michael Barrett was appointed Executive Vice President and General Counsel for Emera. Mr. Barrett was most recently the General Counsel for Emera.

Effective June 30, 2022, Bruce Marchand was appointed Chief Risk and Sustainability Officer for Emera. Mr.  Marchand was most recently the Chief Legal and Compliance Officer for Emera.

FINANCIAL HIGHLIGHTS

Florida Electric Utility

All amounts are reported in USD, unless otherwise stated.

Net Income

Highlights of the net income changes are summarized in the following table:

The impact of the change in the foreign exchange rate increased CAD earnings for the three and six months ended June 30, 2022 by $7 million and $6 million, respectively.

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Operating Revenues – Regulated Electric

Electric revenues increased $131 million to $663 million in Q2 2022, compared to $532 million in Q2 2021. Year-to-date 2022, electric revenues increased $194 million to $1,173 million, compared to $979 million for the same period in 2021. Increases in both periods were due to higher fuel recovery clause revenue as a result of increased fuel costs, new rates effective January 2022, favourable weather and customer growth.

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 $69 million to $225 million in Q2 2022, compared to $156 million in Q2 2021 and, year-to-date 2022, increased $77 million to $361 million, compared to $284 million in the same period in 2021. The increases in both periods were primarily due to higher natural gas prices.

Average fuel cost per megawatt hour (“MWh”) increased to $39 per MWh in Q2 2022 compared to $28 per MWh in Q2 2021. Year-to-date, average fuel cost per MWh increased to $35 per MWh compared to $29 per MWh in the same period in 2021. The increases in both periods were primarily due to higher natural gas prices.

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Canadian Electric Utilities

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

(2) Income from equity investments excludes $7 million in NSPML unrecoverable costs, after-tax, for the six months ended June 30, 2022 (2021 – nil).

Canadian Electric Utilities’ contribution to consolidated adjusted net income is summarized in the following table:

Net Income

Highlights of the net income changes are summarized in the following table:

NSPI

Operating Revenues – Regulated Electric

Operating revenues increased $34 million to $375 million in Q2 2022, compared to $341 million in Q2 2021. Year-to-date 2022, operating revenues increased $100 million to $884 million compared to $784 million for the same period in 2021. The increases in both periods were primarily due to increased recovery of fuel costs from an industrial customer and increased residential and commercial class sales volumes.

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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 $62 million to $235 million in Q2 2022, compared to $173 million in Q2 2021, and year-to-date 2022 increased $153 million to $538 million, compared to $385 million in the same period in 2021. Increases in both periods were due to increased provision recognized as part of the Nova Scotia Cap-and-Trade Program, increased commodity pricing, and increased sales volumes, partially offset by changes in generation mix.

The provision for the Nova Scotia Cap-and-Trade program was $39 million for the three months ended June 30, 2022 (2021 – $1 million) and $112 million for the six months ended June 30, 2022 (2021 – $3 million). This non-cash accrual represents the estimated future cost of acquiring emissions credits for the 2019 through 2022 compliance period. These costs are estimated based on forecasted emissions for the compliance period and are sensitive to changes to forecasts of energy received from Muskrat Falls for the remainder of 2022 and the actual emissions profile.

Average fuel cost per MWh increased in Q2 2022 to $94 per MWh, compared to $71 per MWH in Q2 2021. Year-to-date 2022, average fuel cost per MWh increased to $91 per MWh compared to $68 per MWh in 2021. This was primarily due to increased provision recognized as part of the Nova Scotia Cap-and-Trade Program and increased commodity pricing. The increase was partially offset by a favourable change in generation mix.

NSPI’s FAM regulatory asset balance increased $126 million to $271 million at June 30, 2022 from $145 million at December 31, 2021 due to an under-recovery of current period fuel costs.

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Gas Utilities and Infrastructure

All amounts are reported in USD, unless otherwise stated.

(1) Operating revenues – regulated gas includes $12 million of finance income from Brunswick Pipeline (2021 - $12 million) for the three months ended June 30, 2022 and $23 million (2021 - $23 million) for the six months ended June 30, 2022; however, it is excluded from the gas revenues analysis below.

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

Net Income

Highlights of the net income changes are summarized in the following table:

The impact of the change in the foreign exchange rate on CAD earnings for the three and six months ended June 30, 2022 was minimal.

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Operating Revenues – Regulated Gas

Gas Utilities and Infrastructure’s operating revenues increased $68 million to $266 million in Q2 2022, compared to $198 million in Q2 2021 and year-to-date 2022 increased $154 million to $664 million, compared to $510 million in the same period in 2021. The increases in both periods were due to higher purchased gas adjustment clause revenues at PGS and NMGC as a result of higher gas prices and higher base revenues at PGS due to increased off-system sales and customer growth.

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

Regulated Cost of Natural Gas

Regulated cost of natural gas increased $61 million to $116 million in Q2 2022, compared to $55 million in Q2 2021 and year-to-date 2022 increased $139 million to $318 million, compared to $179 million in the same period in 2021. The increases in both periods were due to higher gas prices at PGS and NMGC.

Gas sales by type are summarized in the following table:    

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Other Electric Utilities

All amounts are reported in USD, unless otherwise stated.

Other Electric Utilities’ contribution to consolidated adjusted net income is summarized in the following table:

Excluding the change in MTM, Other Electric Utilities’ CAD contribution to consolidated net income in Q2 2022 was $8 million, compared to nil in Q2 2021. Year-to-date, CAD contribution increased by $2 million to $9 million in 2022, compared to $7 million in 2021. Increases in both periods were due to the return of unclaimed cash from the acquisition of a non-controlling interest in 2016, higher sales at BLPC, and lower interest expense. Year-over-year, the increase was partially offset by the recognition of Hurricane Dorian insurance proceeds at GBPC in 2021.

The impact of the change in the foreign exchange rate on CAD earnings for the three and six months ended June 30, 2022 was minimal.

Operating Revenues – Regulated Electric

Operating revenues increased $15 million to $102 million in Q2 2022, compared to $87 million for Q2 2021. Year-to-date, revenues increased $35 million to $196 million compared to $161 million in the same period in 2021. The increases in both periods resulted from higher fuel revenue at BLPC due to higher fuel prices.

Electric sales volumes were 302 GWh in Q2 2022, compared to 306 GWh in Q2 2021. Year-to-date, electric sales volumes were 609 GWh, compared to 595 GWh for the same period in 2021.

22

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power increased $17 million to $61 million in Q2 2022, compared to $44 million in Q2 2021. Year-to-date 2022, regulated fuel for generation and purchased power increased $34 million to $111 million, compared to $77 million in 2021. The increases in both periods were due to higher fuel prices at BLPC.

Other

(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 MTM loss, pre-tax of $307 million in Q2 2022 (2021 – $205 million loss) and a loss of $117 million year-to-date (2021 – $167 million loss).

(3) Net of income tax recovery of $91 million for the three months ended June 30, 2022 (2021 – $62 million recovery) and $37 million recovery for the six months ended June 30, 2022 (2021 – $49 million recovery).

Other’s contribution to consolidated adjusted net income is summarized in the following table:

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Net Income

Highlights of the net income changes are summarized in the following table: