ERRAF Emera Inc (PK)

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, 2024

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, 2024

Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its consolidated subsidiaries and investments (collectively referred to as “Emera” or the “Company”) during the second quarter of, and year-to-date 2024 relative to the same periods in 2023; and its financial position as at June 30, 2024 relative to December 31, 2023. 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 MD&A should be read in conjunction with the Emera unaudited condensed consolidated interim financial statements and supporting notes as at and for the three and six months ended June 30, 2024; and the Emera annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2023. Emera follows United States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”). Additional information related to Emera, including the Company’s Annual Information Form, can be found on SEDAR+ at www.sedarplus.ca.

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, 2024, Emera’s rate-regulated subsidiaries and investments include:

On June 4, 2024, Emera completed the sale of its indirect minority equity interest in the Labrador Island Link Partnership (“LIL”). For further details, refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.

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 United States dollars (“USD”) unless otherwise stated.

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TABLE OF CONTENTS

FORWARD-LOOKING INFORMATION

This MD&A contains “forward-looking information” (“FLI”) and statements which reflect the current view with respect to the Company’s expectations regarding future growth, results of operations, performance, the expected timing and outcome of the pending sale of NMGC, 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 FLI, although not all FLI contains these identifying words. The FLI 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 FLI 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 FLI. Factors that could cause results or events to differ from current expectations include, without limitation: regulatory and political risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; liquidity and capital market risk; changes in credit ratings; future dividend growth, rate base growth, and adjusted earnings per common share (“EPS”) 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 risk, including higher frequency and severity of weather events; risk of wildfires; unanticipated maintenance and other expenditures; system operating and maintenance risk; derivative financial instruments and hedging; interest rate risk; inflation risk; counterparty risk; disruption of fuel supply; country risks; supply chain risk; environmental risks; foreign exchange (“FX”); regulatory and government decisions, including changes to environmental legislation, financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of service area; risk of failure of information technology (“IT”) infrastructure and cybersecurity risks; uncertainties associated with infectious diseases, pandemics and similar public health threats; 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 FLI, as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the FLI. All FLI 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 FLI 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 the United States (“US”), Canada 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.

The majority of Emera’s investments in rate-regulated businesses are located in Florida with other investments in Nova Scotia, New Mexico and the Caribbean. Emera’s portfolio of regulated utilities intends to provide 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 forecasted to be approximately $9 billion over the 2024 through 2026 period with approximately $2 billion of additional potential capital investments over the same period. The capital investment plan includes significant investments across the portfolio in renewable and cleaner generation, reliability and system integrity investments, infrastructure modernization and expansion to meet the needs of new and existing customers, and technologies to better support the business and customer experiences. It is anticipated that approximately 75 per cent of this capital will be made within Emera’s two utility operations in Florida. The pace of capital investment is expected to continue beyond 2026 resulting in an anticipated compound annual rate base growth of approximately seven per cent to eight per cent through 2029.

Emera’s capital investment plan is being funded primarily through internally generated cash flows, debt raised at the operating company level consistent with regulated capital structures, equity, and select asset sales. Generally, 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 (“DRIP”) and at-the-market program (“ATM program”). Maintaining investment-grade credit ratings is a priority of the Company.

Emera has provided an average compound annual adjusted EPS growth rate of five to seven per cent through 2027, which will primarily be supported by the capital investment plan and related rate base growth.

Emera has provided annual dividend growth guidance of one to two per cent. 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 in the near term, it is expected to return to that range over time. For further information on the non-GAAP ratios “Adjusted EPS” and “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 (“MTM”) 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 USD relative to the CAD. 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.

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Energy markets worldwide are experiencing significant change and Emera is well-positioned to continue to respond to shifting customer demands and meet the challenges of digitization, decarbonization and decentralized generation, within complex regulatory environments.

Customers depend on the energy provided by Emera’s utility operations and are looking for more choice, better control, and greater reliability. The costs of decentralized generation and storage have become more competitive and advancing technologies are transforming how utilities operate and interact with customers. Concurrently, climate change and the increased frequency of extreme weather events are shaping government energy policy and driving a requirement for increased investments to replace aging infrastructure and harden systems to ensure system resiliency and reliability. These factors combined with inflation, higher interest rates and higher cost of capital increase energy costs, and thus customer rates, at a time when affordability is a challenge.

Emera’s strategy is centered on investing in its operating utilities to deliver value to their customers and in so doing grow earnings and cash flow for shareholders.

Building on the meaningful progress in reducing carbon emissions across its operations, Emera is continuing its efforts to reduce the emission profile of the energy delivered to customers and to meet government carbon reduction requirements.

Subject to the Company’s regulatory obligations and other external factors, Emera is working to achieve the following goals compared to corresponding 2005 levels:

Emera seeks to deliver on these goals while maintaining its focus on investing in reliability and staying focused on the cost impacts 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.

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

Adjusted Net Income Attributable to Common Shareholders, Adjusted EPS – 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 MTM adjustments and the gain on sale, after tax and transaction costs of Emera’s indirect minority equity interest in the LIL (“LIL equity interest”).

Management believes excluding from net income the effect of MTM valuations and changes thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows. Management therefore excludes MTM adjustments for evaluation of performance and incentive compensation.

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The MTM adjustments are related to the following:

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

In Q2 2024, Emera recognized a gain on the sale of its LIL equity interest. Management believes excluding the gain on sale, after tax and transaction costs 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’s LIL equity interest, refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.

Emera calculates adjusted net income for the Other Electric Utilities and Other segments. Reconciliation to the nearest GAAP measure is included in each segment. Refer to “Financial Highlights – Other Electric Utilities” and “Financial Highlights – Other” sections.

Adjusted EPS – basic and dividend payout ratio of adjusted net income are non-GAAP ratios which are calculated using adjusted net income, as described above. For further details on dividend payout ratio of adjusted net income, see the “Dividend Payout Ratio” section in Emera’s 2023 annual MD&A.

The following reconciles net income attributable to common shareholders to adjusted net income:

(1) Net of income tax expense of $75 million for the three and six months ended June 30, 2024 (2023 – nil).

(2) Net of income tax recovery of $52 million for the three months ended June 30, 2024 (2023 – $55 million recovery) and $56 million income tax recovery for the six months ended June 30, 2024 (2023 – $64 million expense).

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 excluding the income effect of MTM adjustments and the gain on sale, after transaction costs, of the LIL equity interest.

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

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

CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Earnings

Gain on Sale of LIL Equity Interest

On June 4, 2024, Emera completed the sale of its LIL equity interest. A gain on sale of $182 million after transaction costs ($107 million, after tax and transaction costs, or $0.37 per common share), was recognized in “Other Income, net” on the Condensed Consolidated Statements of Income and included in the Other segment. For further details on the transaction, refer to the “Other Developments” section.

Earnings Impact of MTM (Loss) Gain, After-Tax

MTM loss, after-tax decreased $5 million to $129 million in Q2 2024, compared to $134 million in Q2 2023, primarily due to lower amortization of gas transportation assets at Emera Energy Services (“EES”). Year-to-date, the 2023 MTM gain, after-tax of $158 million, decreased $296 million to a $138 million MTM loss, after-tax for the same period in 2024. The year-over-year change was primarily due to changes in existing positions partially offset by higher amortization of gas transportation assets at EES.

Consolidated Financial Highlights

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The following table highlights significant quarter-over-quarter and year-over-year changes in adjusted net income from 2023 to 2024:

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

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Consolidated Income Statement Highlights

Operating Revenues

For Q2 2024, operating revenues increased $199 million compared to Q2 2023 and, excluding increased MTM loss of $44 million, increased $155 million. Year-to-date in 2024, operating revenues decreased $216 million compared to 2023 and, excluding increased MTM loss of $366 million, increased by $150 million. These increases were due to new rates at NSPI, PGS and TEC; a change in the fuel cost recovery methodology for an industrial customer in 2023 at NSPI; and the impact of a weaker CAD, partially offset by lower storm surcharge revenue at TEC (offset in OM&G). Year-over-year, increased operating revenues were also partially offset by lower fuel and asset optimization revenues at NMGC; and decreased marketing and trading margin at EES.

Operating Expenses

Operating expenses for Q2 2024 increased $134 million and year-to-date 2024 increased $176 million, compared to the same periods in 2023. These increases were due to a change in fuel cost recovery for an industrial customer in 2023 at NSPI; higher OM&G due to increased investment in reliability initiatives at NSPI; increased T&D costs at TEC; higher labour costs at PGS and NMGC; and higher depreciation at TEC and PGS, partially offset by lower storm cost recognition at TEC (offset in revenue). Year-over-year, increased also due to the timing of long-term compensation hedges at Corporate, partially offset by the reversal of the Nova-Scotia Cap-and-Trade Program provision in 2023 at NSPI; lower cost of natural gas at NMGC; and the Nova Scotia Renewable Electric Regulations (“RER”) penalty recognized at NSPI in Q1 2023.

Other Income, Net

For Q2 2024, other income, net increased $133 million and year-to-date 2024 increased $126 million compared to the same periods in 2023, primarily due to the gain on sale, after transaction costs, of Emera’s LIL equity interest.

Interest Expense, Net

For Q2 2024, interest expense, net increased $15 million and year-to-date 2024 increased $35 million compared to the same periods in 2023 due to higher interest rates and increased borrowings to support ongoing operations.

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Income Tax Expense (Recovery)

For Q2 2024, income tax expense increased $72 million compared to Q2 2023 due to the tax impacts of the gain on sale of Emera’s LIL equity interest. Year-to-date in 2024, income tax expense, net decreased $62 million compared to 2023 due to decreased income before provision for income taxes, excluding the gain on sale of LIL equity interest. This was partially offset by the tax impact of the gain on sale of LIL equity interest.

Net Income and Adjusted Net Income

For Q2 2024, net income attributable to common shareholders, compared to Q2 2023, was favourably impacted by the $107 million gain on sale, after tax and transaction costs, of the LIL equity interest and favourably impacted by the $5 million decrease in MTM losses, after-tax. Excluding these changes, adjusted net income decreased $11 million, primarily due to decreased earnings at NMGC and NSPI; higher Corporate interest expense due to increased interest rates and increased total average debt, and FX losses on the translation of USD short-term debt balances in Corporate. These were partially offset by increased earnings at PGS and TEC and increased Corporate income tax recovery due to increased losses before provision for income taxes.

Year-to-date 2024, net income attributable to common shareholders, compared to the same period in 2023, was favourably impacted by the $107 million gain on sale, after tax and transaction costs, of the LIL equity interest and unfavourably impacted by the $296 million increase in MTM losses, after-tax. Excluding these changes, adjusted net income decreased $63 million. The decrease was primarily due to decreased earnings at NMGC, NSPI, TEC and EES; increased Corporate interest expense due to increased interest rates and increased total average debt; higher Corporate OM&G due to the timing of long-term compensation hedges; and FX losses on the translation of USD short-term debt balances in Corporate. These were partially offset by increased earnings at PGS; and increased Corporate income tax recovery due to increased losses before provision for income taxes.

EPS – Basic and Adjusted EPS – Basic

EPS – basic was higher in Q2 2024 due to the impact of higher earnings, as discussed above, partially offset by an increase in weighted average shares outstanding. Adjusted EPS – basic was lower in Q2 2024 due to the decreased adjusted earnings as discussed above, and an increase in weighted average shares outstanding.

EPS – basic and adjusted EPS – basic were lower year-to-date in 2024 due to decreased earnings, as discussed above, and an increase in weighted average shares outstanding.

Effect of Foreign Currency Translation

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. For additional details on the effects of foreign currency translation, refer to the Company’s 2023 annual MD&A.

The relevant CAD/USD exchange rates for 2024 and 2023 are as follows:

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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) Excludes $88 million USD MTM loss, after-tax, for the three months ended June 30, 2024 (2023 – $132 million USD MTM loss, after-tax) and $89 million USD MTM loss, after-tax, for the six months ended June 30, 2024 (2023 – $100 million USD MTM gain, after-tax).

The translation impact of a weaker CAD on US denominated earnings was more than offset by unrealized losses on FX hedges used to mitigate translation risk of USD earnings. Combined, these decreased net income by $11 million in Q2 2024 and $13 million year-to-date, compared to the same periods in 2023. Weakening of the CAD increased adjusted net income by $2 million in Q2 2024 and $1 million year-to-date compared to the same periods in 2023. Impacts of the changes in the translation of the CAD include the impacts of Corporate FX hedges used to mitigate translation risk of USD earnings in the Other segment.

BUSINESS OVERVIEW AND OUTLOOK

There have been no material changes in Emera’s business overview and outlook from the Company’s 2023 annual MD&A, except for the updates disclosed below. Emera’s results have been impacted by macroeconomic conditions, specifically higher interest rates as well as other impacts of inflation. These conditions are likely to continue for the near term. For information on general economic risk, including interest rate and inflation risk, refer to the “Enterprise Risk and Risk Management – General Economic Risk” in Emera’s 2023 annual MD&A. For details on Emera’s reportable segments, refer to note 1 of the Q2 2024 unaudited condensed consolidated interim financial statements.

Florida Electric Utility

TEC anticipates earning towards the lower end of the ROE range in 2024 but expects earnings to be higher than 2023. Normalizing 2023 for weather, TEC sales volumes in 2024 are projected to be higher than 2023 due to customer growth. TEC expects customer growth rates in 2024 to be comparable to 2023, reflective of the expected economic growth in Florida.

On April 24, 2024, the US Environmental Protection Agency issued its final rules for certain electric generating units. The rules include new greenhouse gas standards, which apply only to existing coal-fired and new natural gas electric generating units and will therefore have limited impact on TEC. They also include new coal combustion residual (“CCR”) rules. TEC is currently evaluating the impact of the new CCR rule at the Big Bend Power Station. TEC expects that prudently incurred costs to comply with new environmental regulations would be eligible for recovery from customers through either the Environmental Cost Recovery Clause or base rates.

On April 2, 2024, TEC requested a base rate increase, reflecting an increased revenue requirement of $297 million USD, effective January 1, 2025, and additional adjustments of $100 million USD and $72 million USD for 2026 and 2027, respectively. TEC’s proposed rates include recovery of solar generation projects, energy storage capacity, a more resilient and modernized energy control center, and other resiliency and reliability projects. A decision by the FPSC is expected by the end of 2024.

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On April 2, 2024, TEC requested a mid-course adjustment to its fuel and capacity charges, reflecting a $138 million USD reduction over 12 months, from June 2024 through May 2025. The requested reduction is due to a decrease in actual and projected 2024 natural gas prices since TEC submitted its projected 2024 costs in the fall of 2023. On May 7, 2024, the FPSC voted to approve the mid-course adjustment.

In 2024, capital investment in the Florida Electric Utility segment is expected to be $1.3 billion USD (2023 – $1.3 billion USD), including allowance for funds used during construction (“AFUDC”). Capital projects include solar investments, grid modernization, storm hardening investments and building resilience.

Canadian Electric Utilities

NSPI

NSPI expects earnings in 2024 to be consistent with 2023 and anticipates earning below its allowed ROE range in 2024. Sales volumes are expected to be higher in 2024 than 2023.

On June 27, 2024, the UARB approved the deferred recognition of $25 million in incremental operating costs incurred during the Hurricane Fiona storm restoration efforts in September 2022. Following UARB approval, the $25 million was reclassified to “Regulatory assets” from “Other long-term assets”. The UARB also directed NSPI to reclassify $10 million of undepreciated costs related to assets retired because of Hurricane Fiona to “Regulatory assets” from “Property, plant and equipment” on the Condensed Consolidated Balance Sheets. NSPI will begin amortizing both of these regulatory assets over a 10-year period beginning July 1, 2024.

On June 13, 2024, the UARB approved $238 million of capital investment, including AFUDC, for the Battery Energy Storage System Project. The project is comprised of three 50 MW, four-hour battery facilities. Two facilities are anticipated to be in-service in late 2025 and the third facility in 2026.

On April 30, 2024, NSPI applied to the UARB for recovery of $22 million of major storm restoration costs deferred to NSPI’s UARB approved storm rider in 2023. If approved, the 2023 costs deferred to the storm rider would be recovered over a 12-month period beginning January 1, 2025. A decision from the UARB is expected by the end of 2024.

On April 17, 2024, the UARB approved the sale of $117 million of the FAM regulatory asset to Invest Nova Scotia, a provincial Crown corporation. On April 30, 2024, the transaction closed and the $117 million was remitted to NSPI, which resulted in a corresponding decrease of the FAM regulatory asset. NSPI is collecting the amortization and financing costs related to the $117 million from customers on behalf of Invest Nova Scotia over a 10-year period which began in Q2 2024 and is remitting those amounts to Invest Nova Scotia quarterly.

In 2024, capital investment, including AFUDC, is expected to be $480 million (2023 – $451 million). NSPI is primarily investing in capital projects required to support power system reliability and reliable service for customers.

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 (the “Province”). For further discussion on environmental legislation and regulations and associated risks, refer to the “Business Overview and Outlook – Canadian Electric Utilities” and “Enterprise Risk and Risk Management” sections respectively of Emera’s 2023 annual MD&A. Recent developments related to provincial and federal environmental laws and regulations are outlined below.

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Nova Scotia Energy Reform Act:

On April 5, 2024, the Province enacted Bill 404 - Energy Reform (2024) Act. This legislation implements certain recommendations made by the Clean Electricity Solutions Task Force, which was established by the Province to advise the provincial government on Nova Scotia’s transition away from coal to more renewable sources of energy. The legislation enacted the Energy and Regulatory Board Act, which established the Nova Scotia Energy Board (“NSEB”). The NSEB is a new board which will regulate energy and utility entities in Nova Scotia, with a mandate of increased focus on meeting energy transition demands. The legislation also enacts the More Access to Energy Act, which provides for the establishment of and phased transition to the Nova Scotia Independent Energy System Operator. NSPI is fully engaged in working with the Province on these initiatives.

RER:

On May 26, 2023, NSPI initiated an appeal, through a proceeding with the UARB, of the $10 million penalty levied on NSPI by the Province for non-compliance with the RER compliance period ending in 2022. The hearing for the matter is currently scheduled for January 2025.

NSPML

Equity earnings from NSPML in 2024 are expected to be consistent with 2023.

On July 4, 2024, NSPML submitted an application to the UARB requesting recovery of approximately $158 million in Maritime Link costs for 2025. A decision is expected in Q4 2024.

On December 21, 2023, NSPML received approval from the UARB to collect up to $164 million in 2024 from NSPI for the recovery of costs associated with the Maritime Link subject to a holdback of $4 million per month. There was no holdback recorded year-to-date in 2024. NSPML expects to file an application to terminate the holdback mechanism in 2024.

NSPML does not anticipate any significant capital investment in 2024.

LIL

On June 4, 2024, Emera completed the sale of its LIL equity interest. For further information, refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.

Gas Utilities and Infrastructure

On August 5, 2024, Emera announced an agreement to sell NMGC. The transaction is expected to close in late 2025, subject to certain approvals, including approval by the NMPRC. For more information on the pending transaction, refer to the “Other Developments” section.

Gas Utilities and Infrastructure USD earnings are anticipated to be higher in 2024 than 2023, primarily due to a base rate increase effective January 2024 at PGS and a base rate increase effective October 2024 at NMGC, partially offset by increased operating expenses and lower asset optimization revenues expected at NMGC.

PGS expects rate base to be higher than in 2023 and anticipates earning within its allowed ROE range in 2024. USD earnings for 2024 are expected to be significantly higher than in 2023 primarily due to higher revenue from new base rates in support of significant ongoing system investment and continued customer growth in 2024, which is expected to be consistent with Florida’s population growth rates.

NMGC expects 2024 rate base to be higher than 2023, with slightly lower USD earnings as a result of increased operating expenses and lower asset optimization revenues, partially offset by higher revenue from new base rates, effective October 2024. NMGC anticipates earning slightly below its authorized ROE in 2024. Customer growth is expected to be consistent with historical trends.

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On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates to become effective in October 2024. On March 1, 2024, NMGC filed with the NMPRC a settlement with the support of all parties in the case for an increase of $30 million USD in annual base revenues and maintaining NMGC’s ROE at 9.375 per cent. The rates reflect the recovery of increased operating costs and capital investments in pipeline projects and related infrastructure, as well as a new customer information and billing system. NMGC also agreed to withdraw, and to not reassert in a future rate case application, its request for a regulatory asset for costs associated with its 2022 application for a certificate of public convenience and necessity for a liquefied natural gas storage facility in New Mexico. The NMPRC approved the rate case settlement on July 25, 2024.

In 2024, capital investment in the Gas Utilities and Infrastructure segment is expected to be approximately $445 million USD (2023 – $495 million USD), including AFUDC. PGS and NMGC will make investments to maintain the reliability of their systems and support customer growth.

Other Electric Utilities

Other Electric Utilities’ USD earnings in 2024 are expected to increase over the prior year due to higher sales volumes at BLPC.

On August 1, 2024, as required by the GBPA Operating Protocol and Regulatory Framework Agreement, GBPC filed a rate plan proposal. The proposal seeks a revision in base rates, charges and tariff classifications effective January 1, 2025 for a three-year period ending December 31, 2027. The proposed rates are based on an 8.5 per cent to 8.7 per cent allowable regulated return on rate base and a target regulatory ROE of 12.87 per cent. A decision is expected from the GBPA before the end of 2024.

On May 24, 2024, the Government of Barbados signed the Income Tax (Amendment and Validation) Act into law. The legislation, effective January 1, 2024, implemented a corporate income tax rate of 9 per cent, requiring BLPC to remeasure its deferred income tax liabilities. On July 18, 2024, BLPC requested the deferred recovery of the $5 million USD remeasurement. BLPC is seeking amortization of the costs over a period to be approved by the FTC during a future rate setting process. A decision by the FTC is expected in Q4 2024.

On May 24, 2024, the Government of Barbados signed the Corporation Top-up Tax (Amendment) Act (“Top-up Tax Act”) into law. The legislation, effective January 1, 2024, establishes an effective tax rate of 15 per cent for qualifying entities through the imposition of a top-up tax. The Top-up Tax Act is not expected to have a material impact to Emera.

On June 1, 2024, the Electricity Act, 2024 took effect. The legislation purports to remove the jurisdiction of the GBPA over GBPC and to have the Utilities Regulation and Competition Authority, another Bahamian regulator, regulate GBPC. The GBPA has opposed the legislated removal of its regulatory authority over GBPC, citing conflict with the Hawksbill Creek Agreement, the 1955 agreement with the Bahamian government that provided for the development and administration of the Freeport area. Management expects the matter of regulatory jurisdiction over GBPC to be the subject of legal proceedings, however, does not foresee that the legislation or the outcome of such proceedings will have a material impact to Emera.

In 2021, BLPC submitted a general rate review application to the FTC. In September 2022, the FTC granted BLPC interim rate relief, allowing an increase in base rates of approximately $1 million USD per month. On February 15, 2023, the FTC issued a decision on the application which included the following significant items: an allowed regulatory ROE of 11.75 per cent, an equity capital structure of 55 per cent, a directive to update the major components of rate base to September 16, 2022, and a directive to establish regulatory liabilities totalling approximately $71 million USD. On March 7, 2023, BLPC filed a Motion for Review and Variation (the “Motion”) and applied for a stay of the FTC’s decision, which was subsequently granted. On November 20, 2023, the FTC issued their decision dismissing the Motion. Interim rates continue to be in effect through to a date to be determined in a final decision and order.

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On December 1, 2023, BLPC appealed certain aspects of the FTC’s February 15 and November 20, 2023 decisions to the Supreme Court of Barbados in the High Court of Justice (the “Court”) and requested that they be stayed. On December 11, 2023, the Court granted the stay. BLPC’s position is that the FTC made errors of law and jurisdiction in their decisions and believes the success of the appeal is probable, and as a result, the adjustments to BLPC’s final rates and rate base, including any adjustments to regulatory assets and liabilities, have not been recorded at this time. The appeal is currently scheduled to be heard in December 2024. Management does not expect the final decision and order to have a material impact on adjusted net income.

In 2024, capital investment in the Other Electric Utilities segment is expected to be approximately $80 million USD (2023 – $47 million USD), primarily in projects to support system reliability.

Other

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 expected to deliver annual adjusted net income within its guidance range of $15 to $30 million USD.

The adjusted net loss from the Other segment is expected to be higher in 2024 due to higher Corporate OM&G, higher preferred dividend expense, and a lower contribution to net income from Emera Energy primarily as a result of one-time investment tax credits at Bear Swamp in 2023.

The Other segment does not anticipate any significant capital investment in 2024.

CONSOLIDATED BALANCE SHEET HIGHLIGHTS

Significant changes in the Consolidated Balance Sheets between December 31, 2023 and June 30, 2024 include:

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OTHER DEVELOPMENTS

Pending Sale of NMGC

On August 5, 2024, Emera announced an agreement to sell its indirect wholly owned subsidiary NMGC for a total enterprise value of approximately $1.3 billion USD, consisting of cash proceeds and the transfer of debt and customary closing adjustments. The transaction is expected to close in late 2025, subject to certain approvals, including approval by the NMPRC.

As at June 30, 2024, the held-for-sale (“HFS”) criteria were not met and therefore NMGC remained classified as held-and-used as of the balance sheet date. During the subsequent event period, the HFS criteria were met, and therefore the assets and liabilities will be reclassified as HFS in Emera’s Q3 2024 financial statements.

As the transaction proceeds will be lower than the carrying amount of the assets and liabilities being sold, Emera assessed the NMGC reporting unit for goodwill impairment by comparing the fair value of expected transaction proceeds to the carrying value, including goodwill of $366 million USD (“carrying amount”). The goodwill of the reporting unit was determined to be impaired. At the time of transaction agreement, the non-cash goodwill impairment loss was estimated to be approximately $70 million, after tax. In Q3 2024, Emera will record a non-cash goodwill impairment which will be measured at the lower of carrying amount and fair value at that point in time. The Company may take future non-cash goodwill impairments as a result of continued investments in the business and the length of time until transaction close, including transaction costs. The total expected loss including non-cash charges and transaction costs recognized between transaction announcement and close could be materially higher.

Canadian Tax Legislation Changes

On June 20, 2024, Bill C-59, an Act to implement certain provisions of the fall economic statement tabled in Parliament on November 21, 2023, and certain provisions of the budget tabled in Parliament on March 28, 2023, was enacted. Bill C-59 includes the excessive interest and financing expenses limitation (“EIFEL”) regime, which is effective January 1, 2024. EIFEL applies to limit a company’s net interest and financing expense deduction to no more than 30 per cent of EBITDA for tax purposes. Any denied interest and financing expenses under the EIFEL regime can be carried forward indefinitely. The Company is still in the process of assessing the impacts of the enactment of the EIFEL regime, including investigating opportunities to restructure its Canadian-based financing to ensure that any denied interest and financing expenses in the near-term will be utilized in future periods. There are no impacts required to be recognized in the Company’s financial statements as at June 30, 2024.

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On June 20, 2024, Bill C-69, an Act to implement certain provisions of the budget tabled in Parliament on April 16, 2024, was enacted. Bill C-69 includes the Canadian Global Minimum Tax Act (“GMTA”), a regime based on the rules of the Organisation for Economic Co-operation and Development (“OECD”). The GMTA ensures that large multinational corporations are subject to a minimum effective tax rate of 15 per cent on their profits wherever they do business. The GMTA did not have a material impact on the Company in Q2 2024.

Sale of LIL Equity Interest

On June 4, 2024, Emera completed the sale of its 31.1 per cent LIL equity interest for a total transaction value of $1.2 billion, including cash proceeds of $957 million and $235 million for assuming Emera’s contractual obligation to fund the remaining initial capital investment, which represents additional LIL equity interest for the acquirer. Cash proceeds from the sale in the amount of $30 million is held in escrow pending finalization of certain agreements with the LIL general partner. The escrow proceeds receivable is held at fair value and included in the gain on sale, after transaction costs. As of June 30, 2024, the estimated fair value of the escrow proceeds receivable is $25 million. A gain on sale, after tax and transaction costs, of $107 million, was included in the Other segment (the gain on sale, net of transaction costs of $182 million was recognized in “Other Income, net” on the Condensed Consolidated Statements of Income). Proceeds from the sale are being used to reduce corporate debt and fund investment in the Company’s regulated utility businesses.

Appointments

Board of Directors

Effective June 26, 2024, Carla Tully joined the Emera Board of Directors. Ms. Tully is the former Chief Executive Officer and Co-Founder of Earthrise Energy, PBC, an energy transition company. She also previously served as Executive Vice President and Managing Director of Renewable Energy at MAP Energy and held various senior leadership roles with AES Corporation. 

Effective March 6, 2024, Brian J. Porter joined the Emera Board of Directors. Mr. Porter is the former President and Chief Executive Officer of The Bank of Nova Scotia (Scotiabank), a global bank operating in Canada and the Americas.

FINANCIAL HIGHLIGHTS

Florida Electric Utility

The impact on Q2 2024 and year-to-date earnings related to the change in the FX rate increased CAD earnings by $3 million.

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

Canadian Electric Utilities

On June 4, 2024, Emera completed the sale of its LIL equity interest. For further details on the transaction, refer to the “Other Developments” section.

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

(1) For more information on the changes in fuel cost recovery methodology for an industrial customer, refer to note 6 in Emera’s 2023 annual audited consolidated financial statements.

(2) In Q1 2023, the Province provided NSPI with additional emissions allowances sufficient to achieve compliance with the 2019 through 2022 Nova Scotia Cap-and-Trade Program compliance period and accrued compliance costs related to the expected purchase of emissions credits were reversed, resulting in a fuel cost recovery of $166 million.

(3) On February 21, 2024, the UARB’s decision on the FAM audit findings relating to fiscal 2020 and 2021 were released and included a disallowance of costs, net of tax and interest, of $3 million recorded in OM&G (the associated interest expense of $1 million is recorded in ‘Interest expense, net’).

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Gas Utilities and Infrastructure

On August 5, 2024, Emera announced an agreement to sell NMGC. The transaction is expected to close in late 2025, subject to certain approvals, including regulatory approval by the NMPRC. For more information on the pending transaction, refer to the “Other Developments” section.

The impact on Q2 2024 and year-to-date earnings related to the change in the FX rate was minimal.

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

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Other Electric Utilities.

The impact on Q2 2024 and year-to-date earnings related to the change in the FX rate on CAD earnings was minimal.

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

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Other

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

Corporate

Corporate’s adjusted loss is summarized in the following table:

(1) Operating expenses include OM&G and depreciation.

(2) Other includes realized gains and losses on FX hedges entered into to hedge USD denominated operating unit earnings exposure.

(3) Includes a realized net loss, pre-tax of $3 million ($2 million after-tax) for the three months ended June 30, 2024 (2023 – $2 million net loss, pre-tax and $2 million loss, after-tax) and a $4 million net loss, pre-tax ($3 million after-tax) for the six months ended June 30, 2024 (2023 – $5 million net loss, pre-tax and $4 million loss, after-tax) on FX hedges, as discussed above.

(4) Excludes a MTM loss, after-tax, of $10 million for the three months ended June 30, 2024 (2023 – $12 million gain, after-tax) and a MTM loss, after-tax of $12 million for the six months ended June 30, 2024 (2023 – $16 million gain, after-tax).

(5) Excludes a gain on sale, after-tax and transaction costs, of $107 million for the three and six months ended June 30, 2024 (2023 – nil).

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LIQUIDITY AND CAPITAL RESOURCES

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

Emera’s future liquidity and capital needs will be predominately for working capital requirements, ongoing rate base investment, business acquisitions, greenfield development, dividends and debt servicing. Emera has an approximate $9 billion capital investment plan over the 2024 through 2026 period with approximately $2 billion of additional potential capital investments over the same period. Capital investments at Emera’s regulated utilities are subject to regulatory approval.

Emera plans to use cash from operations, debt raised at the utilities, equity, proceeds from the sale of its LIL equity interest, and the pending sale of NMGC to support normal operations, repayment of existing debt, and capital requirements. Debt raised at certain of the Company’s utilities is subject to applicable regulatory approvals. Generally, equity requirements in support of the Company’s capital investment plan are expected to be funded through issuance of preferred equity and issuance of common equity through Emera’s DRIP and ATM programs.

Emera has total committed credit facilities with varying maturities that cumulatively provide $3.2 billion CAD and $1.6 billion USD of credit, with approximately $2.0 billion CAD and $1.2 billion USD undrawn and available at June 30, 2024. The Company was holding a cash balance of $348 million at June 30, 2024. For further discussion, refer to the “Debt Management” section below.

Consolidated Cash Flow Highlights

Significant changes in the Condensed Consolidated Statements of Cash Flows between the six months ended June 30, 2024 and 2023 include:

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Cash Flow from Operating Activities

Net cash provided by operating activities increased $242 million to $1,193 million for the six months ended June 30, 2024, compared to $951 million for the same period in 2023.

Cash from operations before changes in working capital increased $81 million year-over-year. This increase was due to the favourable change in regulatory liabilities due to the 2023 gas hedge settlements at NMGC, increased electric revenue at NSPI, proceeds from the FAM asset sale to Invest Nova Scotia at NSPI, and increased earnings and recovery of the conservation clause expense at PGS. These were partially offset by lower fuel clause recoveries and decreased earnings at TEC, reversal of the Nova Scotia Cap-and-Trade Program provision in Q1 2023 and higher Corporate interest.

Changes in working capital increased operating cash flows by $161 million year-over-year. This increase was due to favourable changes in cash collateral positions at NSPI, reversal of the Nova Scotia Cap-and-Trade accrual at NSPI in Q1 2023, timing of accounts receivable at TEC, and changes in fuel inventory at NSPI. These were partially offset by unfavourable changes in accounts receivable at NMGC due to the receipt of its 2023 gas hedge settlement and unfavourable changes in cash collateral positions at EES.

Cash Flow from Investing Activities

Net cash used in investing activities decreased $928 million to $415 million for the six months ended June 30, 2024, compared to $1,343 million for the same period in 2023. The decrease was due to the proceeds of $927 million received on the sale of Emera’s LIL equity interest.

Capital investments, including AFUDC, for the six months ended June 30, 2024, were $1,368 million compared to $1,368 million for the same period in 2023. Details of the 2024 capital investment by segment are shown below:

Cash Flow from Financing Activities

Net cash used in financing activities increased $1,398 million to $998 million for the six months ended June 30, 2024, compared to cash provided by financing activities of $400 million for the same period in 2023. This increase was due to higher repayment of Emera’s committed credit facilities using the LIL transaction proceeds, repayment of short-term debt at TEC, 2023 proceeds of long-term debt at NSPI, and retirement of long-term debt at Emera. These were partially offset by the issuance of long-term debt at TEC, proceeds from the fixed-to-fixed reset rate junior subordinated notes issuance by EUSHI Finance, Inc. and lower net repayments under committed credit facilities at NSPI.

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Contractual Obligations

As at June 30, 2024, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:

(1) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at June 30, 2024, including any expected required payment under associated swap agreements.

(2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $133 million related to a gas transportation contract between PGS and SeaCoast through 2040.

(3) Annual requirement to purchase electricity from Independent Power Producers or other utilities over varying contract lengths.

(4) The estimated contractual obligation is calculated as the current legislatively required contributions to the registered funded pension plans, plus the estimated costs of further benefit accruals contracted under NSPI’s Collective Bargaining Agreement and estimated benefit payments related to other unfunded benefit plans.

NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. In December 2023, the UARB approved the collection of up to $164 million from NSPI for the recovery of Maritime Link costs in 2024. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to UARB approval.

Emera has committed to obtain certain transmission rights in New Brunswick during summer periods (April through October, inclusive) for Nalcor Energy’s use, if requested, effective August 15, 2021 and continuing for 50 years. As transmission rights are contracted, the obligations are included within “Other” in the above table.

Debt Management

In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to committed syndicated revolving and non-revolving bank lines of credit in either CAD or USD, per the table below as at June 30, 2024.