Exhibit 99.1

Management’s Discussion & Analysis

As at November 8, 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 third quarter of, and year-to-date 2024 relative to the same periods in 2023; and its financial position as at September 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 nine months ended September 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 September 30, 2024, Emera’s rate-regulated subsidiaries and investments include:

Emera Rate-Regulated Subsidiary or Equity Investment	Accounting Policies Approved/Examined By
Subsidiary
Tampa Electric Company (“TEC”)	Florida Public Service Commission (“FPSC”) and the Federal Energy Regulatory Commission (“FERC”)
Nova Scotia Power Inc. (“NSPI”)	Nova Scotia Utility and Review Board (“UARB”)
Peoples Gas System, Inc. (“PGS”)	FPSC
New Mexico Gas Company, Inc. (“NMGC”)	New Mexico Public Regulation Commission (“NMPRC”)
SeaCoast Gas Transmission, LLC (“SeaCoast”)	FPSC
Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”)	Canadian Energy Regulator (“CER”)
Barbados Light & Power Company Limited (“BLPC”)	Fair Trading Commission, Barbados (“FTC”)
Grand Bahama Power Company Limited (“GBPC”)	The Grand Bahama Port Authority (“GBPA”)
Equity Investments
NSP Maritime Link Inc. (“NSPML”)	UARB
Maritimes & Northeast Pipeline Limited Partnership and Maritimes & Northeast Pipeline, LLC (“M&NP”)	CER and FERC
St. Lucia Electricity Services Limited (“Lucelec”)	National Utility Regulatory Commission

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	2
Introduction and Strategic Overview	3
Non-GAAP Financial Measures and Ratios	4
Consolidated Financial Review	7
Significant Items Affecting Earnings	7
Consolidated Financial Highlights	7
Consolidated Income Statement Highlights	9
Business Overview and Outlook	12
Florida Electric Utility	12
Canadian Electric Utilities	13
Gas Utilities and Infrastructure	15
Other Electric Utilities	15
Other	16
Consolidated Balance Sheet Highlights	17
Other Developments	18
Financial Highlights	20
Florida Electric Utility	20
Canadian Electric Utilities	21

Gas Utilities and Infrastructure	22
Other Electric Utilities	23
Other	24
Liquidity and Capital Resources	26
Consolidated Cash Flow Highlights	27
Contractual Obligations	28
Debt Management	29
Guarantees and Letters of Credit	30
Outstanding Stock Data	31
Transactions with Related Parties	31
Risk Management including Financial Instruments	32
Disclosure and Internal Controls	33
Critical Accounting Estimates	33
Changes in Accounting Policies and Practices	33
Future Accounting Pronouncements	33
Summary of Quarterly Results	35

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.

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 investment 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 guidance 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:

• A 55 per cent reduction in carbon dioxide emissions by 2025.

• The retirement of Emera’s last existing coal unit no later than 2040.

• An 80 per cent reduction in carbon dioxide emissions by 2040.

Emera seeks to deliver on these goals while maintaining its focus on investing in reliability and staying focused on 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 are calculated by adjusting certain GAAP measures for specific items. They may not be comparable to similar measures presented by other entities. 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, charges related to the pending sale of NMGC, and the gain on sale, after tax and transaction costs, of Emera’s indirect minority equity interest in the LIL (“LIL equity interest”). For details of these adjustments, see below.

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

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MTM Adjustments:

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. The MTM adjustments are related to the following:

• held-for-trading (“HFT”) commodity derivative instruments, including adjustments related to the price differential between the point where natural gas is sourced and where it is delivered, and the related amortization of transportation capacity recognized as a result of certain Emera Energy marketing and trading transactions;

• the business activities of Bear Swamp Power Company LLC (“Bear Swamp”) included in Emera’s equity income;

• equity securities held in BLPC and Emera Energy; and

• FX hedges entered into to hedge USD denominated operating unit earnings exposure.

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

Charges Related to the Pending Sale of NMGC:

On August 5, 2024, Emera entered into an agreement to sell NMGC. In Q3 2024, the Company recognized $206 million in non-cash goodwill and other impairment charges, after-tax and an additional loss of $19 million in estimated transaction costs, after-tax related to the pending sale. Management believes excluding these amounts from net income better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the business. For further details on the pending sale of NMGC, refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.

Gain on Sale of LIL Equity Interest:

In Q2 2024, Emera recognized a $107 million gain, after tax and transaction costs, 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.

Reconciliation of Net Income Attributable to Common Shareholders to Adjusted Net Income

For the	Three months ended September 30				Nine months ended September 30
millions of dollars (except per share amounts)	2024		2023		2024		2023
Net income attributable to common shareholders	$	4	$	101	$	340	$	689
Charges related to the pending sale of NMGC, after-tax (1)(2)		(225)		-		(225)		-
Gain on sale of LIL, after tax and transaction costs (3)		-		-		107		-
MTM (loss) gain, after-tax (4)		(7)		(103)		(145)		55
Adjusted net income	$	236	$	204	$	603	$	634
EPS – basic	$	0.01	$	0.37	$	1.18	$	2.53
Adjusted EPS – basic	$	0.81	$	0.75	$	2.10	$	2.33
(1) Represents (i) $206 million in non-cash goodwill and other impairment charges, after-tax and (ii) $19 million in transaction costs, after-tax for the three and nine months ended September 30, 2024 (2023 – nil).
(2) Net of income tax recovery of $20 million for the three and nine months ended September 30, 2024 (2023 – nil).
(3) Net of income tax expense of $75 million for the nine months ended September 30, 2024 (2023 – nil).
(4) Net of income tax recovery of $4 million for the three months ended September 30, 2024 (2023 – $40 million recovery) and $60 million income tax recovery for the nine months ended September 30, 2024 (2023 – $24 million expense).

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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, charges related to the pending sale of NMGC, and the gain on sale of LIL, after transaction costs.

Reconciliation of Net Income to EBITDA and Adjusted EBITDA

For the	Three months ended September 30				Nine months ended September 30
millions of dollars	2024		2023		2024		2023
Net income (1)	$	23	$	118	$	395	$	738
Interest expense, net		241		235		725		684
Income tax (recovery) expense		(9)		(34)		40		77
Depreciation and amortization		293		266		866		785
EBITDA	$	548	$	585	$	2,026	$	2,284
Charges related to the pending sale of NMGC, excluding income tax		(245)		-		(245)		-
Gain on sale of LIL, after transaction costs, excluding income tax		-		-		182		-
MTM (loss) gain, excluding income tax		(11)		(143)		(205)		79
Adjusted EBITDA	$	804	$	728	$	2,294	$	2,205
(1) Net income is before Non-controlling interest in subsidiaries and Preferred stock dividends.

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CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Earnings

Charges Related to the Pending Sale of NMGC

In Q3 2024, Emera recognized non-cash goodwill and other impairment charges of $221 million ($206 after-tax, or $0.72 per common share) related to the NMGC reporting unit. These charges were recorded in “Impairment charges” on the Condensed Consolidated Statements of Income and included in the Other and Gas Utilities and Infrastructure segments, respectively. For further details on the pending sale of NMGC, refer to the “Other Developments” section. For further details on the non-cash goodwill impairment charge, refer to note 19 in the condensed consolidated interim financial statements.

Additionally, as of September 30, 2024, Emera recorded a loss of $24 million ($19 million after-tax, or $0.06 per common share) in estimated transaction costs related to the pending sale of NMGC. These transaction costs were recorded in “Other Income, net” on the Condensed Consolidated Statement of Income and included in the Other segment. For further details, refer to the “Other Developments” section.

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 $96 million to $7 million in Q3 2024, compared to $103 million in Q3 2023, primarily due to lower amortization of gas transportation assets at Emera Energy Services (“EES”) and a gain on Corporate FX hedges compared to a loss in the prior year. Year-to-date, the 2023 MTM gain, after-tax, of $55 million, decreased $200 million to a $145 million MTM loss, after-tax for the same period in 2024, primarily due to changes in existing positions at EES.

Consolidated Financial Highlights

For the millions of dollars	Three months ended September 30				Nine months ended September 30
Adjusted Net Income	2024		2023		2024		2023
Florida Electric Utility	$	252	$	228	$	524	$	512
Canadian Electric Utilities		26		38		155		179
Gas Utilities and Infrastructure		38		23		180		155
Other Electric Utilities		10		17		27		31
Other		(90)		(102)		(283)		(243)
Adjusted net income	$	236	$	204	$	603	$	634
Charges related to the pending sale of NMGC, after-tax		(225)		-		(225)		-
Gain on sale of LIL, after tax and transaction costs		-		-		107		-
MTM (loss) gain, after-tax		(7)		(103)		(145)		55
Net income attributable to common shareholders	$	4	$	101	$	340	$	689

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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 the	Three months ended		Nine months ended
millions of dollars	September 30		September 30
Adjusted net income – 2023	$	204	$	634
Operating Unit Performance
Increased earnings at TEC due to higher revenues as a result of customer growth and new base rates, lower income tax expense and the impact of a weaker CAD, partially offset by unfavourable weather and higher depreciation. Year-over-year earnings was also partially offset by higher operating, maintenance and general expenses (“OM&G”) due to higher generation and transmission and distribution (“T&D”) costs		24		12
Increased earnings at PGS due to higher revenue from new base rates and customer growth, partially offset by increased depreciation, OM&G, interest expense and income tax expense		15		47
Increased earnings quarter-over-quarter at NSPI due to lower OM&G. Decreased earnings year-over-year due to higher OM&G due to increased reliability initiatives, partially offset by higher revenue from increased residential sales volumes		4		(12)
Decreased earnings year-over-year at NMGC due to lower asset optimization revenues and increased OM&G, partially offset by lower income tax expense		1		(18)
Decreased income from equity investments due to the sale of LIL equity interest		(15)		(16)
Decreased earnings at Emera Energy due to the recognition of investment tax credits in 2023 related to Bear Swamp		(5)		(8)
Decreased earnings at EES due to less favourable market conditions. Year-over-year decrease also reflects favourable hedging opportunities in Q1 2023 as a result of higher natural gas pricing		(3)		(13)
Corporate
Decreased OM&G, pre-tax, primarily due to the timing difference in the valuation of long-term incentive expense and related hedges		32		15
Increased preferred share dividends due to higher dividend rate for series B, C, and H preferred shares		(2)		(6)
Increased interest expense, pre-tax, due to increased interest rates and increased total debt		(6)		(29)
Decreased income tax recovery quarter-over-quarter due to decreased loss before provision for income taxes. Increased income tax recovery year-over-year due to increased loss before provision for income taxes		(7)		8
Other Variances		(6)		(11)
Adjusted net income – 2024	$	236	$	603

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

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For the	Nine months ended September 30
millions of dollars	2024			2023
Operating cash flow before changes in working capital	$	1,732		$	1,813
Change in working capital		220			5
Operating cash flow	$	1,952		$	1,818
Investing cash flow	$	(1,289	)	$	(2,045	)
Financing cash flow	$	(997	)	$	166

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

As at		September 30		December 31
millions of dollars		2024		2023
Total assets	$	39,674	$	39,480
Total long-term debt (including current portion) (1)	$	17,262	$	18,365
(1) Excludes NMGC balances classified as held for sale as at September 30, 2024. For further details refer to the “Other Developments” section and Note 4 in the condensed consolidated interim financial statements.

Consolidated Income Statement Highlights

For the	Three months ended						Nine months ended
millions of dollars	September 30						September 30
(except per share amounts)	2024		2023		Variance		2024		2023		Variance
Operating revenues	$	1,802	$	1,740	$	62	$	5,437	$	5,591	$	(154)
Operating expenses		1,586		1,468		(118)		4,596		4,302		(294)
Income from operations	$	216	$	272	$	(56)	$	841	$	1,289	$	(448)
Other income, net	$	14	$	15	$	(1)	$	232	$	107	$	125
Interest expense, net	$	241	$	235	$	(6)	$	725	$	684	$	(41)
Income tax (recovery) expense	$	(9)	$	(34)	$	(25)	$	40	$	77	$	37
Net income attributable to common shareholders	$	4	$	101	$	(97)	$	340	$	689	$	(349)
Adjusted net income	$	236	$	204	$	32	$	603	$	634	$	(31)
Weighted average shares of common stock outstanding (in millions)		290.0		273.6		16.4		287.5		272.2		15.3
EPS – basic	$	0.01	$	0.37	$	(0.36)	$	1.18	$	2.53	$	(1.35)
EPS – diluted	$	0.01	$	0.37	$	(0.36)	$	1.18	$	2.53	$	(1.35)
Adjusted EPS – basic	$	0.81	$	0.75	$	0.06	$	2.10	$	2.33	$	(0.23)
Dividends per common share declared	$	0.7175	$	0.6900	$	0.0275	$	2.1525	$	2.0700	$	0.0825
Adjusted EBITDA	$	804	$	728	$	76	$	2,294	$	2,205	$	89

Operating Revenues

For Q3 2024, operating revenues increased $62 million compared to Q3 2023 and, excluding decreased MTM loss of $98 million, decreased $36 million. The decrease was due to lower fuel recovery clause and storm surcharge revenue (offset in OM&G) at TEC; decreased marketing and trading margin at EES; lower fuel revenue at NMGC; and unfavourable weather at TEC. These decreases were partially offset by new rates at PGS, NSPI and TEC; the impact of a weaker CAD; and increased customer growth at PGS and TEC.

Year-to-date in 2024, operating revenues decreased $154 million compared to 2023 and, excluding increased MTM loss of $268 million, increased $114 million. The increase was 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; the impact of a weaker CAD; and increased customer growth at PGS, TEC and NSPI. These increases were partially offset by lower fuel recovery clause and storm surcharge revenue (offset in OM&G) at TEC; lower fuel and asset optimization revenues at NMGC; decreased marketing and trading margin at EES; and unfavourable weather at TEC.

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Operating Expenses

Operating expenses for Q3 2024 increased $118 million compared to Q3 2023, and, excluding the goodwill and other impairment charges related to the pending sale of NMGC of $221 million, decreased $103 million due to lower OM&G as a result of lower storm cost recognition at TEC (offset in revenue); the timing difference in the valuation of long-term incentive expense and related hedges at Corporate; and lower fuel for generation and purchased power due to changes in natural gas prices at TEC. These decreases were partially offset by higher depreciation at TEC and PGS.

Operating expenses year-to-date 2024 increased $294 million, compared to 2023, and excluding the goodwill and other impairment charges related to the pending sale of NMGC of $221 million, increased $73 million due to higher depreciation at TEC and PGS; a change in fuel cost recovery for an industrial customer in 2023 at NSPI; higher OM&G due to increased T&D costs and higher regulatory deferrals at TEC, higher labour costs at PGS and NMGC and increased investment in reliability initiatives at NSPI. These increases were partially offset by lower fuel for generation and purchased power due to changes in natural gas prices at TEC; lower natural gas prices at NMGC and PGS; lower storm cost recognition at TEC (offset in revenue); timing difference in the valuation of long-term incentive expense and related hedges at Corporate; and the Nova Scotia Renewable Electric Regulations (“RER”) penalty recognized at NSPI in Q1 2023.

Other Income, Net

For Q3 2024, other income, net decreased $1 million compared to Q3 2024 due to transaction costs related to the pending sale of NMGC, partially offset by higher FX gains.

Year-to-date in 2024, other income, net increased $125 million compared to the same period in 2023 due to the gain on sale, after transaction costs, of Emera’s LIL equity interest, partially offset by transaction costs related to the pending sale of NMGC, lower interest income, and higher FX losses.

Interest Expense, Net

For Q3 2024, interest expense, net increased $6 million and year-to-date 2024 increased $41 million compared to the same periods in 2023 due to higher interest rates and increased borrowings to support ongoing operations.

Income Tax (Recovery) Expense

For Q3 2024, income tax recovery decreased $25 million compared to Q3 2023 due to increased income before provision for income taxes, excluding charges related to the pending sale of NMGC, increased production tax credits related to solar facilities and the tax impact of the charges related to the pending sale of NMGC.

Year-to-date in 2024, income tax expense decreased $37 million compared to 2023 due to decreased income before provision for income taxes, excluding the gain on sale of LIL equity interest and charges related to the pending sale of NMGC. This was partially offset by the net tax impact of the gain on sale of LIL equity interest and charges related to the pending sale of NMGC.

Net Income and Adjusted Net Income

For Q3 2024, net income attributable to common shareholders, compared to Q3 2023, was unfavourably impacted by $225 million in charges related to the pending sale of NMGC, after-tax, and favourably impacted by the $96 million decrease in MTM losses, after-tax. Excluding these changes, adjusted net income increased $32 million, primarily due to increased earnings at TEC, PGS, NSPI and NMGC; and lower Corporate OM&G due to the timing difference in the valuation of long-term incentive expense and related hedges. These were partially offset by decreased earnings at Emera Energy; lower equity earnings from LIL; lower Corporate income tax recovery due to decreased losses before provision for income taxes; increased Corporate interest expense due to increased interest rates and increased total debt; and increased Corporate preferred share dividends.

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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 $200 million increase in MTM losses, after-tax, and $225 million in charges related to the pending sale of NMGC, after-tax. Excluding these changes, adjusted net income decreased $31 million. The decrease was primarily due to decreased earnings at NMGC, Emera Energy, and NSPI; lower equity earnings from LIL; increased Corporate interest expense due to increased interest rates and increased total debt; and increased Corporate preferred share dividends. These were partially offset by increased earnings at PGS and TEC; decreased Corporate OM&G due to the timing difference in the valuation of long-term incentive expense and related hedges; and higher income tax recovery due to increased loss before provision for income taxes.

EPS – Basic and Adjusted EPS – Basic

EPS – basic was lower in Q3 2024 due to the impact of decreased earnings, as discussed above, and an increase in weighted average shares outstanding. Adjusted EPS – basic was higher in Q3 2024 due to increased adjusted earnings as discussed above, partially offset by an increase in weighted average shares outstanding.

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

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:

	Three months ended				Nine months ended				Year ended
	September 30				September 30				December 31
For the	2024		2023		2024		2023		2023
Weighted average CAD/USD	$	1.36	$	1.34	$	1.36	$	1.34	$	1.35
Period end CAD/USD exchange rate	$	1.35	$	1.35	$	1.35	$	1.35	$	1.32

The table below includes Emera’s significant segments whose contributions to adjusted net income are recorded in USD currency:

	Three months ended				Nine months ended
For the	September 30				September 30
millions of USD	2024		2023		2024		2023
Florida Electric Utility	$	186	$	170	$	385	$	381
Gas Utilities and Infrastructure (1)(2)		25		12		122		101
Other Electric Utilities		8		13		20		23
Other segment (3)(4)		(58)		(32)		(108)		(77)
Total (2)(4)(5)	$	161	$	163	$	419	$	428
(1) Includes USD adjusted net income from PGS, NMGC, SeaCoast and M&NP.
(2) Excludes $6 million USD after-tax in other impairment charges associated with the pending sale of NMGC
(3) Includes Emera Energy’s USD adjusted net income from EES, Bear Swamp and interest expense on Emera Inc.’s USD denominated debt.
(4) Excludes $160 million USD, after-tax in charges associated with the pending sale of NMGC
(5) Excludes $183 million USD MTM loss, after-tax, for the three months ended September 30, 2024 (2023 – $57 million USD MTM loss, after-tax) and $272 million USD MTM loss, after-tax, for the nine months ended September 30, 2024 (2023 – $43 million USD MTM gain, after-tax).

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The translation impact of a weaker CAD on USD earnings increased net income by $7 million in Q3 2024 compared to the same period in 2023. Year-to-date 2024, the impact of a weaker CAD on US denominated earnings was more than offset by the realized and unrealized losses on FX hedges used to mitigate the translation risk of USD earnings, resulting in a $6 million decrease to net income compared to the same period in 2023. Weakening of the CAD increased adjusted net income by $2 million in Q3 2024 and $3 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 Q3 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 September 26, 2024, Hurricane Helene passed 100 miles west of Tampa and made landfall approximately 200 miles north of Tampa, in Taylor County, as a Category 4 hurricane. TEC’s service territory was impacted by the tropical storm force winds and storm surge which resulted in a peak number of customers out of 100,000. As of September 30, 2024, TEC deferred $45 million USD to the storm reserve for future recovery, with a minimal impact to earnings. Additional storm restoration costs expected to be deferred to the storm reserve regulatory account in Q4 2024 are estimated to be upwards of $10 million USD, with minimal impact expected to earnings.

On October 9, 2024, Hurricane Milton made landfall approximately 50 miles south of Tampa, near Sarasota, and was the worst weather event to impact the area in over 100 years. The Category 3 hurricane had a significant impact on TEC’s service territory which resulted in a peak number of customers out of 600,000. The total cost of restoration expected to be deferred to the storm reserve regulatory asset is estimated to be $320 million – $370 million USD, with minimal impact expected to earnings.

As at September 30, 2024, total restoration costs charged to the storm reserve account, including Q3 2024 costs related to Hurricane Helene, have exceeded the storm reserve balance (for additional details on the storm reserve, refer to note 6 in Emera’s 2023 annual audited consolidated financial statements) and therefore $35 million USD has been deferred as a regulatory asset for future recovery. The Q4 2024 restoration costs for Hurricane Helene and Milton will also be deferred to the storm reserve regulatory account. TEC expects to make a regulatory filing with the FPSC for the recovery of the storm reserve regulatory account balance and replenishment of the original storm reserve. TEC has not determined the recovery approach and timeframe at this time but is considering several alternatives.

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. The rate case hearing occurred in August 2024 and a decision by the FPSC is expected by early December 2024.

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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 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 approved 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, or higher than, 2023 and anticipates earning below its allowed ROE range in 2024. Sales volumes are expected to be higher in 2024 than 2023.

On September 24, 2024, the Government of Canada finalized an agreement with NSPI, NSPML and the Province of Nova Scotia (the “Province”) on terms and conditions for a federal loan guarantee (“FLG”) of $500 million in debt to be issued by NSPML to help Nova Scotia customers manage unrecovered costs of the replacement energy that was required during the several years of delay in the Muskrat Falls hydroelectricity project. Subject to certain conditions, including regulatory approval by the UARB, the net proceeds of the NSPML debt issuance will be transferred to NSPI as a refund of a portion of previous NSPML assessment payments and be applied against the Fuel Adjustment Mechanism (“FAM”) regulatory asset balance. NSPML will then increase its annual assessment charge to NSPI to recover the refund and related financing costs over a 28-year period. On September 25, 2024, NSPI and NSPML filed applications with the UARB related to the FLG. A decision on the NSPML application, which would trigger the debt issuance and refund to NSPI, is expected in Q4 2024. A decision on the NSPI application, which would reflect the necessary 2025 fuel rates to service the incremental NSPML debt, is expected in Q1 2025.

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 “PP&E” on the Condensed Consolidated Balance Sheets. NSPI began 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.

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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 $510 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. 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.

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 April 2025.

NSPML

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

On September 24, 2024, the Government of Canada finalized an agreement with NSPI, NSPML, and the Province on terms and conditions for a FLG of $500 million in debt to be issued by NSPML. For further information, refer to the NSPI section above.

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 late Q4 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.

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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 approval by the NMPRC. As a result of the pending sale, NMGC’s assets and liabilities were classified as held for sale in Q3 2024. 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 in 2024 than in 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.

On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates. 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. New rates became effective October 1, 2024.

In 2024, capital investment in the Gas Utilities and Infrastructure segment is expected to be approximately $450 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. During Q2 2024, GBPC customers experienced power interruptions due to unscheduled generation outages. Subsequently, on October 1, 2024, the GBPA suspended its review of GBPC’s rate plan proposal until a period of reliability is re-established by GBPC. GBPC has been executing a comprehensive plan to improve service reliability for its customers during Q4 2024.

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.

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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.

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.

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 $90 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 increased interest expense, 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.

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CONSOLIDATED BALANCE SHEET HIGHLIGHTS

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

millions of dollars	Total Increase (Decrease)		Increase (Decrease) due to held for sale classification (1)		Other Increase (Decrease)		Explanation of Other Increase (Decrease)
Assets
Cash and cash equivalents	$	(327)	$	(4)	$	(323)	Decreased due to investment in PP&E, net repayments on committed credit facilities at Corporate, repayment of short-term debt at TEC, retirement of long-term debt at Emera, TEC and New Mexico Gas Intermediate, Inc. (“NMGI”), and dividends paid on Emera common stock. These were partially offset by cash from operations, proceeds from debt issuances at TEC and EUSHI Finance, Inc., proceeds received on the sale of the LIL equity interest and proceeds from common shares issued
Derivative instruments (current and long-term)		(67)		(14)		(53)	Decreased due to the reversal of 2023 contracts and changes in existing positions at EES
Regulatory assets (current and long-term)		(207)		(25)		(182)	Decreased due to lower deferred income tax regulatory assets due to the sale of LIL equity interest, decreased fuel clause recovery asset balance at TEC due to higher over-recoveries, and lower deferrals related to derivative instruments at NSPI. These were partially offset by increased storm cost recovery clause assets at TEC and NSPI
Receivables and other assets (current and long-term)		(269)		(85)		(184)	Decreased due to lower gas transportation assets and lower trade receivables due to lower commodity prices at EES and lower cash collateral position on derivative instruments and seasonal trends at NSPI. These were partially offset by higher unbilled revenue at TEC
Assets held for sale (current and long-term), net of liabilities		885		885		-	Increased due to the pending sale of NMGC
PP&E, net of accumulated depreciation and amortization		83		(1,672)		1,755	Increased due to capital additions in excess of depreciation and the effect of FX translation of Emera’s non-Canadian affiliates
Investments subject to significant influence		(750)		-		(750)	Decreased primarily due to sale of LIL equity interest
Goodwill		(373)		(284)		(89)	Decreased due to the non-cash impairment charge recognized related to NMGC, partially offset by the effect of FX translation of Emera’s non-Canadian affiliates
(1) On August 5, 2024, Emera announced the sale of NMGC. As at September 30, 2024 NMGC’s assets and liabilities were classified as held for sale. For further details, refer to the ‘Other Developments’ section and note 3 in the condensed consolidated interim financial statements.

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millions of dollars	Total Increase (Decrease)		Increase (Decrease) due to held for sale classification (1)		Other Increase (Decrease)		Explanation of Other Increase (Decrease)
Liabilities and Equity
Short-term debt and long-term debt (including current portion)	$	(1,127)	$	(672)	$	(455)	Decrease due to higher repayment of Emera’s committed credit facilities using the LIL transaction proceeds, repayment of short-term debt at TEC, and retirement of long-term debt at Corporate, TEC and NMGI. These were partially offset by proceeds from long-term debt issuance at TEC, issuance of junior subordinated notes at EUSHI Finance Inc. and the effect of FX translation of Emera’s non-Canadian affiliates
Accounts payable		(135)		(79)		(56)	Decreased due to lower commodity prices at EES
Deferred income tax liabilities, net of deferred income tax assets		(187)		(157)		(30)	No significant change after removing impact of held for sale classification
Regulatory liabilities (current and long-term)		(98)		(268)		170	Increased due to recognition of fuel clause recovery liability due to cost recovery in excess of regulatory asset at TEC, higher cost of removal at TEC and PGS, and the effect of FX translation of Emera’s non-Canadian affiliates
Other liabilities (current and long-term)		167		(30)		197	Increased due to timing of interest payments at Corporate and TEC, higher output-based pricing system (“OBPS”) carbon tax accrual at NSPI and the effect of FX translation of Emera’s non-Canadian affiliates
Common stock		422		-		422	Increased due to shares issued
Accumulated other comprehensive income		207		-		207	Increased due to the effect of FX translation of Emera’s non-Canadian affiliates
Retained earnings		(277)		-		(277)	Decreased due to dividends paid in excess of net income
(1) On August 5, 2024, Emera announced the sale of NMGC. As at September 30, 2024 NMGC’s assets and liabilities were classified as held for sale. For further details, refer to the ‘Other Developments’ section and note 3 in the condensed consolidated interim financial statements.

OTHER DEVELOPMENTS

Pending Sale of NMGC

On August 5, 2024, Emera entered into 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 a result of the pending sale, NMGC’s assets and liabilities were classified as held for sale in Q3 2024.

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 (“FV”) of expected transaction proceeds to the carrying value of net assets, including goodwill of $366 million USD (“carrying amount”). The goodwill of the reporting unit was determined to be impaired and a non-cash goodwill impairment charge of $210 million ($198 million, after-tax) or $155 million USD ($146 million USD, after-tax) was recorded in “Impairment Charges” on the Condensed Consolidated Statements of Income in Q3 2024.

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Following the goodwill impairment assessment, the held for sale assets and liabilities were measured at the lower of their carrying amount or fair value less costs to sell. The measurement resulted in an additional loss for the estimated future transaction costs of $16 million ($13 million after-tax), in addition to incurred transaction costs of $8 million ($6 million after-tax) recorded in “Other Income, net” on the Condensed Consolidated Statements of Income in Q3 2024.

The Company will continue to record depreciation on the NMGC assets through the transaction closing date, as the depreciation continues to be reflected in customer rates and will be reflected in the carryover basis of the assets when sold. Depreciation and amortization of $9 million ($7 million USD) has been recorded on these assets from August 5, 2024, the date they were classified as held for sale, to September 30, 2024.

Increase in Common Dividend

On September 18, 2024, the Emera Board of Directors approved an increase in the annual common share dividend rate to $2.90 from $2.87 per common share. The first payment will be effective November 15, 2024.

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 September 30, 2024.

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 Q3 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 FV and included in the gain on sale, after transaction costs. As of September 30, 2024, the estimated FV 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 were used to reduce corporate debt and fund investment in the Company’s regulated utility businesses.

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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

	Three months ended				Nine months ended
For the	September 30				September 30
millions of USD (except as indicated)	2024		2023		2024		2023
Operating revenues – regulated electric	$	724	$	795	$	1,944	$	2,024
Regulated fuel for generation and purchased power	$	164	$	210	$	471	$	520
Contribution to consolidated net income	$	186	$	170	$	385	$	381
Contribution to consolidated net income – CAD	$	252	$	228	$	524	$	512
Electric sales volumes (Gigawatt hours (“GWh”))		6,437		6,919		16,080		16,529
Electric production volumes (GWh)		6,661		6,749		17,017		17,065
Average fuel cost in dollars per megawatt hour (“MWh”)	$	25	$	31	$	28	$	30

The impact on Q3 2024 and year-to-date earnings related to the change in the FX rate increased CAD earnings by $4 million and $7 million, respectively.

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

For the	Three months ended		Nine months ended
millions of USD	September 30		September 30
Contribution to consolidated net income – 2023	$	170	$	381
Decreased operating revenues primarily due to decreased fuel recovery clause revenue, lower storm surcharge revenue (offset in OM&G) and unfavourable weather of approximately $13 million and $22 million quarter-over-quarter and year-over-year, respectively. These decreases are partially offset by customer growth and new base rates		(71)		(80)
Decreased fuel for generation and purchased power due to lower natural gas prices		46		49
Decreased OM&G due to lower storm cost recognition (offset in revenue). Year-over-year decrease was partially offset by higher generation and T&D costs and timing of deferred clause recoveries		34		31
Increased depreciation and amortization due to additions to facilities and generation projects placed in service		(7)		(23)
Decreased interest expense due to lower borrowings		2		7
Decreased income tax expense due to increased production tax credits related to solar facilities		6		18
Other		6		2
Contribution to consolidated net income – 2024	$	186	$	385

20

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.

	Three months ended				Nine months ended
For the	September 30				September 30
millions of dollars (except as indicated)	2024		2023		2024		2023
Operating revenues – regulated electric	$	399	$	388	$	1,376	$	1,232
Regulated fuel for generation and purchased power (1)	$	243	$	213	$	725	$	543
Contribution to consolidated net income	$	26	$	38	$	155	$	179
Electric sales volumes (GWh)		2,285		2,331		7,849		7,777
Electric production volumes (GWh)		2,428		2,471		8,361		8,255
Average fuel costs in dollars per MWh (2)	$	100	$	86	$	87	$	66
(1) Regulated fuel for generation and purchased power includes NSPI’s FAM on the Condensed Consolidated Statements of Income, however, it is excluded in the segment overview.
(2) Average fuel costs for the nine months ended September 30, 2023 include the reversal of the $166 million Nova Scotia Cap-and-Trade Program provision.

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

	Three months ended				Nine months ended
For the	September 30				September 30
millions of dollars	2024		2023		2024		2023
NSPI	$	14	$	10	$	89	$	101
Equity investment in NSPML		12		13		38		34
Equity investment in LIL		-		15		28		44
Contribution to consolidated net income	$	26	$	38	$	155	$	179

21

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

For the	Three months ended		Nine months ended
millions of dollars	September 30		September 30
Contribution to consolidated net income – 2023	$	38	$	179
Increased operating revenues at NSPI due to new rates, and higher residential sales volumes, partially offset by lower industrial revenue. Year-over-year also increased due to changes in fuel cost recovery methodology for an industrial customer(1) in 2023		11		144
Increased regulated fuel for generation and purchased power at NSPI quarter-over-quarter due to change in generation mix and decreased Nova Scotia OBPS carbon tax accrual, partially offset by lower commodity prices. Increased year-over-year due to reversal of the Nova Scotia Cap-and-Trade Program provision(1) in 2023, change in generation mix, and increased sales volumes, partially offset by decreased commodity prices		(30)		(182)
Increased FAM at NSPI quarter-over-quarter due to a higher under-recovery of fuel costs. Increased year-over-year due to changes in the fuel cost recovery methodology for an industrial customer(1) in 2023 and higher under-recovery of fuel costs, partially offset by the reversal of the Nova Scotia Cap-and-Trade Program provision(1) in 2023		19		56
Increased OM&G year-over-year at NSPI due to increased investment in reliability initiatives and higher IT costs, partially offset by lower storm restoration costs and the RER penalty recognized in Q1 2023		5		(16)
Decreased income from equity investments due to the sale of LIL		(16)		(18)
Decreased income tax recovery year-over-year at NSPI due to decreased tax deductions in excess of accounting depreciation related to PP&E, partially offset by a decrease in the benefit of tax loss carryforwards recognized as a deferred income tax regulatory liability and decreased income before provision for income taxes		3		(7)
Other		(4)		(1)
Contribution to consolidated net income – 2024	$	26	$	155
(1) For more information on the changes in fuel cost recovery methodology for an industrial customer and the $166 million reversal related to the Nova Scotia Cap-and-Trade Program provision, refer to note 6 in Emera’s 2023 annual audited consolidated financial statements.

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. The Company will continue to record depreciation on these assets through the transaction closing date, as the depreciation continues to be reflected in customer rates and will be reflected in the carryover basis of the assets when sold. For more information on the pending transaction, refer to the “Other Developments” section.

	Three months ended				Nine months ended
For the	September 30				September 30
millions of USD (except as indicated)	2024		2023		2024		2023
Operating revenues – regulated gas (1)	$	216	$	193	$	843	$	824
Operating revenues – non-regulated		5		4		12		12
Total operating revenue	$	221	$	197	$	855	$	836
Regulated cost of natural gas	$	34	$	44	$	208	$	292
Contribution to consolidated adjusted net income	$	28	$	17	$	133	$	115
Contribution to consolidated adjusted net income – CAD	$	38	$	23	$	180	$	155
Charges related to the pending sale of NMGC, after-tax (2)		(6)		-		(6)		-
Contribution to consolidated net income	$	22	$	17	$	127	$	115
Contribution to consolidated net income – CAD	$	30	$	23	$	172	$	155
Gas sales volumes (millions of Therms)		729		705		2,370		2,333
(1) Operating revenues – regulated gas includes $11 million of finance income from Brunswick Pipeline (2023 – $12 million) for the three months ended September 30, 2024 and $34 million (2023 – $35 million) for the nine months ended September 30, 2024.
(2) Includes an other impairment charge, net of an income tax recovery of $2 million for the three and nine months ended September 30, 2024 (2023 – nil)

22

Gas Utilities and Infrastructure’s contribution to consolidated adjusted net income is summarized in the following table:

	Three months ended				Nine months ended
For the	September 30				September 30
millions of USD	2024		2023		2024		2023
PGS	$	24	$	13	$	92	$	58
NMGC		(3)		(4)		16		29
Other		7		8		25		28
Contribution to consolidated adjusted net income	$	28	$	17	$	133	$	115

The impact on Q3 2024 and year-to-date earnings related to the change in the FX rate increased CAD earnings and adjusted earnings by $1 million.

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

For the	Three months ended		Nine months ended
millions of USD	September 30		September 30
Contribution to consolidated net income – 2023	$	17	$	115
Increased gas revenues due to new base rates and customer growth at PGS, partially offset by lower fuel revenues at NMGC		24		27
Decreased asset optimization revenues at NMGC		-		(8)
Decreased cost of natural gas due to lower natural gas prices at NMGC and PGS		10		84
Increased OM&G primarily due to the timing of deferred clause recoveries at PGS and higher labour cost at PGS and NMGC		(5)		(26)
Increased depreciation primarily due to asset growth at PGS, partially offset by reversal of accumulated depreciation in 2023 as a result of the 2021 rate case settlement at PGS		(7)		(26)
Increased interest expense, net primarily due to higher interest rates and increased borrowings to support ongoing operations and capital investments primarily at PGS		(2)		(16)
Increased income tax expense primarily due to increased income before provision for income taxes at PGS, partially offset by lower income before provision for income taxes at NMGC		(4)		(8)
Charges related to the pending sale of NMGC, after-tax		(6)		(6)
Other		(5)		(9)
Contribution to consolidated net income – 2024	$	22	$	127

Other Electric Utilities.

	Three months ended				Nine months ended
For the	September 30				September 30
millions of USD (except as indicated)	2024		2023		2024		2023
Operating revenues – regulated electric	$	110	$	108	$	306	$	286
Regulated fuel for generation and purchased power	$	58	$	57	$	160	$	147
Contribution to consolidated adjusted net income	$	8	$	13	$	20	$	23
Contribution to consolidated adjusted net income – CAD	$	10	$	17	$	27	$	31
Equity securities MTM (loss) gain	$	-	$	(1)	$	1	$	-
Contribution to consolidated net income	$	8	$	12	$	21	$	23
Contribution to consolidated net income – CAD	$	11	$	16	$	29	$	31
Electric sales volumes (GWh)		346		344		984		937
Electric production volumes (GWh)		371		371		1,056		1,017
Average fuel costs in dollars per MWh	$	156	$	154	$	152	$	145

23

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

	Three months ended				Nine months ended
For the	September 30				September 30
millions of USD	2024		2023		2024		2023
BLPC	$	4	$	6	$	14	$	14
GBPC		4		7		8		11
Other		-		-		(2)		(2)
Contribution to consolidated adjusted net income	$	8	$	13	$	20	$	23

The impact on Q3 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:

For the	Three months ended		Nine months ended
millions of USD	September 30		September 30
Contribution to consolidated net income – 2023	$	12	$	23
Increased operating revenues – regulated electric year-over-year due to higher fuel revenue and higher sales volumes at BLPC		2		20
Increased regulated fuel for generation and purchased power year-over-year due to higher sales volumes at BLPC		(1)		(13)
Increased OM&G due to higher generation costs BLPC and GBPC		(5)		(9)
Contribution to consolidated net income – 2024	$	8	$	21

Other

	Three months ended				Nine months ended
For the	September 30				September 30
millions of dollars	2024		2023		2024		2023
Marketing and trading margin (1) (2)	$	(7)	$	-	$	42	$	61
Other non-regulated operating revenue		7		7		22		22
Total operating revenues – non-regulated	$	-	$	7	$	64	$	83
Contribution to consolidated adjusted net (loss) income	$	(90)	$	(102)	$	(283)	$	(243)
Charges related to the pending sale of NMGC, after-tax (3)		(217)		-		(217)		-
Gain on sale, after tax and transaction costs (4)(5)		-		-		107		-
MTM (loss) gain, after-tax (6)		(8)		(102)		(147)		55
Contribution to consolidated net (loss) income	$	(315)	$	(204)	$	(540)	$	(188)
(1) Marketing and trading margin represents EES’s purchases and sales of natural gas and electricity, pipeline and storage capacity costs and energy asset management services’ revenues.
(2) Marketing and trading margin excludes a pre-tax MTM loss of $37 million for the three months ended September 30, 2024 (2023 – $101 million loss) and a loss of $198 million year-to-date (2023 – $85 million gain).
(3) Includes a goodwill impairment charge of $210 million ($198 million after-tax) and transaction costs of $24 million ($19 million after-tax) for the three and nine months ended September 30, 2024 (2023 – nil).
(4) On June 4, 2024, Emera completed the sale of its LIL equity interest. For further details on the transaction, refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.
(5) Net of income tax expense of $75 million for the nine months ended September 30, 2024 (2023 – nil).
(6) Net of income tax recovery of $4 million for the three months ended September 30, 2024 (2023 – $40 million recovery) and $60 million income tax recovery for the nine months ended September 30, 2024 (2023 – $24 million expense).

24

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

	Three months ended				Nine months ended
For the	September 30				September 30
millions of dollars	2024		2023		2024		2023
Emera Energy
EES	$	(7)	$	(4)	$	14	$	27
Other		2		7		4		12
Corporate – see breakdown of adjusted contribution below		(82)		(99)		(287)		(265)
Block Energy LLC		(3)		(5)		(13)		(14)
Other		-		(1)		(1)		(3)
Contribution to consolidated adjusted net (loss) income	$	(90)	$	(102)	$	(283)	$	(243)

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

For the	Three months ended		Nine months ended
millions of dollars	September 30		September 30
Contribution to consolidated net (loss) income – 2023	$	(204)	$	(188)
Decreased marketing and trading margin quarter-over-quarter and year-over-year due to less favourable market conditions, specifically lower natural gas prices and volatility. Year-over-year decrease also reflects favourable hedging opportunities in Q1 2023		(7)		(19)
Decreased OM&G primarily due to the timing difference in the valuation of long-term incentive expense and related hedges		34		18
Increased interest expense due to increased interest rates and increased total debt		(5)		(27)
Corporate FX losses on the translation of USD short-term debt balances		-		(5)
Decreased income tax recovery quarter-over-quarter due to decreased loss before provision for income taxes and the recognition of investment tax credits related to Bear Swamp facility upgrades in 2023. Increased income tax recovery year-over-year due to increased loss before provision for income taxes, partially offset by the recognition of investment tax credits related to Bear Swamp facility upgrades in 2023		(12)		4
Charges related to the pending sale of NMGC, after-tax		(217)		(217)
Gain on sale of LIL, after tax and transaction costs		-		107
Decreased MTM loss, after-tax, quarter-over-quarter due to lower amortization of gas transportation assets at EES and a gain on Corporate FX hedges compared to a loss in prior year. Year-over-year, the 2023 MTM gain decreased to a loss for the same period in 2024 due to changes in existing positions at EES		94		(202)
Other		2		(11)
Contribution to consolidated net (loss) income – 2024	$	(315)	$	(540)

25

Corporate

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

	Three months ended				Nine months ended
For the	September 30				September 30
millions of dollars	2024		2023		2024		2023
Operating expenses (1)	$	-	$	(32)	$	(51)	$	(66)
Interest expense		(90)		(84)		(270)		(241)
Income tax recovery		27		34		94		86
Preferred dividends		(18)		(16)		(54)		(48)
Other (2)(3)		(1)		(1)		(6)		4
Corporate adjusted net loss (4)(5)(6)	$	(82)	$	(99)	$	(287)	$	(265)

(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 September 30, 2024 (2023 – $2 million net loss, pre-tax and $1 million loss, after-tax) and a $7 million net loss, pre-tax ($5 million after-tax) for the nine months ended September 30, 2024 (2023 – $7 million net loss, pre-tax and $5 million loss, after-tax) on FX hedges, as discussed above.

(4) Excludes a MTM gain, after-tax, of $6 million for the three months ended September 30, 2024 (2023 – $11 million loss, after-tax) and a MTM loss, after-tax of $6 million for the nine months ended September 30, 2024 (2023 – $5 million gain, after-tax).

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

(6) Excludes certain charges related to the pending sale of NMGC of $234 million ($217 million after-tax) for the three and nine months ended September 30, 2024 (2023 – nil).

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 $2.8 billion CAD and $1.6 billion USD of credit, with approximately $1.5 billion CAD and $831 million USD undrawn and available at September 30, 2024. The Company was holding a cash balance of $244 million, which includes $4 million classified as assets held for sale, related to the pending sale of NMGC, at September 30, 2024. For further discussion, refer to the “Debt Management” section below.

26

Consolidated Cash Flow Highlights

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

millions of dollars	2024		2023		Change
Cash, cash equivalents, and restricted cash, beginning of period	$	588	$	332	$	256
Provided by (used in):
Operating cash flow before changes in working capital		1,732		1,813		(81)
Change in working capital		220		5		215
Operating activities	$	1,952	$	1,818	$	134
Investing activities		(1,289)		(2,045)		756
Financing activities		(997)		166		(1,163)
Effect of exchange rate changes on cash, cash equivalents, restricted cash, and cash associated with assets held for sale		10		2		8
Cash, cash equivalents, restricted cash and cash associated with assets held for sale, end of period	$	264	$	273	$	(9)

Cash Flow from Operating Activities

Net cash provided by operating activities increased $134 million to $1,952 million for the nine months ended September 30, 2024, compared to $1,818 million for the same period in 2023.

Cash from operations before changes in working capital decreased $81 million year-over-year. This decrease was due to increased storm cost recovery regulatory asset related to Hurricane Helene at TEC, lower fuel clause recoveries at TEC, and reversal of the Nova Scotia Cap-and-Trade Program provision in Q1 2023. These were partially offset by 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.

Changes in working capital increased operating cash flows by $215 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 favourable changes in fuel inventory at NSPI and TEC. 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 and lower natural gas inventory at EES.

Cash Flow from Investing Activities

Net cash used in investing activities decreased $756 million to $1,289 million for the nine months ended September 30, 2024, compared to $2,045 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, partially offset by higher capital investment.

Capital investments, including AFUDC, for the nine months ended September 30, 2024, were $2,259 million, compared to $2,090 million for the same period in 2023. Details of the 2024 capital investment by segment are shown below:

● $1,375 million – Florida Electric Utility (2023 – $1,212 million);

● $389 million – Canadian Electric Utilities (2023 – $346 million);

● $437 million – Gas Utilities and Infrastructure (2023 – $482 million);

● $54 million – Other Electric Utilities (2023 – $43 million); and

● $4 million – Other (2023 – $7 million).

27

Cash Flow from Financing Activities

Net cash used in financing activities increased $1,163 million to $997 million for the nine months ended September 30, 2024, compared to cash provided by financing activities of $166 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, TEC and NMGI. These were partially offset by proceeds from the fixed-to-fixed reset rate junior subordinated notes issuance by EUSHI Finance Inc., issuance of long-term debt at TEC, higher issuance of common stock and lower net repayments under committed credit facilities at EES and NSPI.

Contractual Obligations

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

millions of dollars	2024		2025		2026		2027		2028		Thereafter		Total
Long-term debt principal (1)	$	24	$	512	$	3,112	$	83	$	582	$	13,729	$	18,042
Interest payment obligations (2)(3)		350		860		762		671		667		8,558		11,868
Transportation (4)(5)		216		654		483		488		420		3,401		5,662
Purchased power (6)		82		289		275		324		325		3,562		4,857
Capital projects		712		245		62		10		1		1		1,031
Fuel, gas supply and storage (7)		217		445		86		11		4		-		763
Asset retirement obligations		6		3		1		1		2		406		419
Pension and post-retirement obligations (8)		7		30		39		48		32		154		310
Other		34		148		62		50		37		233		564
	$	1,648	$	3,186	$	4,882	$	1,686	$	2,070	$	30,044	$	43,516

As detailed below, contractual obligations at September 30, 2024 includes those related to NMGC. On completion of the sale of NMGC, all of the remaining future contractual obligations will be transferred to the buyer. For further details on the pending transaction, refer to the “Other Developments” section.

(1) Includes $653 million related to NMGC (2026: $95 million and $558 million thereafter).

(2) 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 September 30, 2024, including any expected required payment under associated swap agreements.

(3) Includes $338 million related to NMGC (2024: $7 million, 2025: $24 million, 2026: $24 million, 2027: $22 million, 2028: $22 million, and $239 million thereafter).

(4) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $128 million related to a gas transportation contract between PGS and SeaCoast through 2040.

(5) Includes $77 million related to NMGC (2024: $10 million, 2025: $27 million, 2026: $19 million, 2027: $12 million, and 2028: $9 million).

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

(7) Includes $203 million related to NMGC (2024: $52 million, 2025: $107 million, 2026: $36 million, 2027: $5 million, and 2028: $3 million).

(8) 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.

28

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 September 30, 2024.

millions of Canadian dollars (unless otherwise indicated)	Maturity		Credit Facilities		Utilized		Undrawn and Available
Emera – Unsecured committed revolving credit facility		June 2029	$	1,300	$	263	$	1,037
TEC (in USD) – Unsecured committed revolving credit facility		December 2028		800		386		414
NSPI – Unsecured committed revolving credit facility		June 2029		800		291		509
TECO Finance (in USD) – Unsecured committed revolving credit facility		December 2028		400		294		106
NSPI – Unsecured non-revolving facility		June 2025		300		300		-
PGS (in USD) – Unsecured revolving facility		December 2028		250		65		185
Emera – Unsecured non-revolving facility		December 2024		200		200		-
Emera – Unsecured non-revolving facility		February 2025		200		200		-
NMGC (in USD) – Unsecured revolving credit facility		December 2026		125		16		109
Other (in USD) – Unsecured committed revolving credit facilities		Various		21		4		17

Emera and its subsidiaries have certain financial and other covenants associated with their debt and credit facilities. Covenants are tested regularly, and the Company is in compliance with covenant requirements as at September 30, 2024.

Recent significant financing activity for Emera and its subsidiaries are discussed below by segment:

Florida Electric Utilities

On July 12, 2024, TEC repaid a $300 million USD note upon maturity. This note was repaid with proceeds from commercial paper.

On April 1, 2024, TEC amended its $800 million USD unsecured committed revolving credit facility to extend the maturity date from December 17, 2026 to December 1, 2028. There were no other changes in commercial terms from the prior agreement.

On January 30, 2024, TEC issued $500 million USD of senior unsecured bonds that bear interest at 4.90 per cent with a maturity date of March 1, 2029. Proceeds from the issuance were primarily used for the repayment of short-term borrowings outstanding under the 5-year credit facility.

Canadian Electric Utilities

On June 24, 2024, NSPI amended its unsecured committed revolving credit facility to extend the maturity date from December 16, 2027 to June 24, 2029. There were no other material changes in commercial terms from the prior agreement.

On June 24, 2024, NSPI amended its unsecured non-revolving credit facility to extend the maturity date from July 15, 2024 to June 24, 2025 and reduce the facility from $400 million to $300 million. There were no other material changes in commercial terms from the prior agreement.

On June 13, 2024, NSPI entered a non-revolving credit facility to finance the Battery Energy Storage Project. NSPI can request funds under the facility quarterly for amounts related to incurred project costs up to the total commitment of the lessor of $120 million and 45.06 per cent of the total eligible project costs over the term of the agreement. The facility will be available until 6 months after completion of the project, not to exceed May 21, 2027 and matures 20 years following the end of the period. As at September 30, 2024, NSPI had utilized $16 million from the facility, which bears interest at 2.51 per cent.

Gas Utilities and Infrastructure

On July 30, 2024, NMGI repaid its $150 million USD fixed rate notes upon maturity.

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Other Electric Utilities

On May 2, 2024, BLPC amended its $92 million Barbadian dollar ($46 million USD) loan facility to extend the maturity date from February 19, 2025 to July 19, 2028. There were no other material changes in commercial terms from the prior agreement.

Other

On June 24, 2024, Emera amended its unsecured committed revolving credit facility increasing the facility from $900 million to $1,300 million. Emera also extended the maturity date from June 24, 2027 to June 24, 2029. There were no other material changes in commercial terms from the prior agreement.

On June 24, 2024, Emera repaid its $400 million unsecured non-revolving credit facility set to mature in August 2024.

On June 18, 2024, EUSHI Finance, Inc., completed an issuance of $500 million USD fixed-to-fixed reset rate junior subordinated notes. The notes initially bear interest at a rate of 7.625 per cent, and will reset on December 15, 2029, and every five years thereafter, to a rate per annum equal to the five-year U.S. treasury rate plus 3.136 per cent. The notes mature on December 15, 2054. EUSHI Finance, Inc., at its option, may redeem the notes, in whole or in part, 90 days prior to the first interest reset date, and any semi-annual interest payment date thereafter, at a redemption price equal to the principal amount.

Proceeds from the $500 million USD note issuance discussed above were used to repay an Emera US Finance LP $300 million USD senior note upon maturity in June 2024, and to repay an NMGI $150 million USD fixed rate notes upon maturity in July 2024. The remaining proceeds were used for general corporate purposes.

On June 17, 2024, Emera repaid $200 million from the December 2024 unsecured non-revolving facility, decreasing the facility from $400 million to $200 million. There were no other material changes in commercial terms from the prior agreement.

On April 1, 2024, TECO Finance amended its $400 million USD unsecured committed revolving credit facility to extend the maturity date from December 17, 2026 to December 1, 2028. There were no other changes in commercial terms from the prior agreement.

On February 16, 2024, Emera amended its $400 million unsecured non-revolving facility to extend the maturity date from February 19, 2024 to February 19, 2025. There were no other changes in commercial terms from the prior agreement. On July 19, 2024, Emera reduced the amount of the facility from $400 million to $200 million.

Guarantees and Letters of Credit

Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2023

annual MD&A, with material updates as noted below:

Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The expiry date of this letter of credit was extended to June 2025. The amount committed as at September 30, 2024 was $58 million (December 31, 2023 – $56 million).

Emera has provided an indemnity to a counterparty in relation to certain future tax amounts that could arise from specific future changes in Canadian federal law, subject to certain conditions and limitations. No such changes in law have been proposed at this time. A reasonable estimate of the potential amount of future payments that could result from future claims under this indemnity cannot be calculated, but the risk of having to make any significant payments under this indemnity is considered to be remote.

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Outstanding Stock Data

Common Stock

Issued and outstanding:	millions of shares		millions of dollars
Balance, December 31, 2023		284.12	$	8,462
Issuance of common stock under ATM program (1)		3.61		181
Issued under the DRIP, net of discounts		4.61		217
Senior management stock options exercised and Employee Share Purchase Plan		0.50		24
Balance, September 30, 2024		292.84	$	8,884

(1) For the three months ended September 30, 2024, 2,882,000 common shares were issued under Emera’s ATM program at an average price of $51.18 per share for gross proceeds of $148 million ($146 million, net of after-tax issuance costs). For the nine months ended September 30, 2024, 3,606,996 common shares were issued under Emera’s ATM program at an average price of $50.58 per share for gross proceeds of $182 million ($181 million net of after-tax issuance costs). As at September 30, 2024, an aggregate gross sales limit of $18 million remained available for issuance under the ATM program.

As at November 6, 2024, the amount of issued and outstanding common shares was 292.9 million.

If all outstanding stock options were converted as at November 6, 2024, an additional 3.8 million common shares would be issued and outstanding.

Preferred Stock

As at November 6, 2024, Emera had the following preferred shares issued and outstanding: Series A – 4.9 million; Series B – 1.1 million; Series C – 10.0 million; Series E – 5.0 million; Series F – 8.0 million; Series H – 12.0 million; Series J – 8.0 million, and Series L – 9.0 million. Emera’s preferred shares do not have voting rights unless the Company fails to pay, in aggregate, eight quarterly dividends.

TRANSACTIONS WITH RELATED PARTIES

In the ordinary course of business, Emera provides energy and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Intercompany balances and intercompany transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities, in accordance with accounting standards for rate-regulated entities. All material amounts are under normal interest and credit terms.

Significant transactions between Emera and its associated companies are as follows:

● Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Condensed Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $41 million for the three months ended September 30, 2024 (2023 – $44 million) and $123 million for the nine months ended September 30, 2024 (2023 – $122 million). NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments. For further details, refer to the “Business Overview and Outlook – Canadian Electric Utilities – NSPML” and “Contractual Obligations” sections.

● Natural gas transportation capacity purchases from M&NP are reported in the Condensed Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues – non-regulated, totalled $2 million for the three months ended September 30, 2024 (2023 – $2 million) and $8 million for the nine months ended September 30, 2024 (2023 – $10 million).

There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at September 30, 2024 and at December 31, 2023.

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

There have been no material changes in Emera’s risk management profile and practices from those disclosed in the Company’s 2023 annual MD&A.

Derivative Assets and Liabilities Recognized on the Balance Sheet

As at millions of dollars	September 30 2024			December 31 2023
Regulatory Deferral:
Derivative instrument assets (1)	$	39		$	16
Derivative instrument liabilities (2)		(46)			(76)
Regulatory assets (1)		54			88
Regulatory liabilities (2)		(24)			(17)
Net asset	$	23		$	11
HFT Derivatives:
Derivative instrument assets (1)	$	131		$	202
Derivative instrument liabilities (2)		(409)			(421)
Net liability	$	(278)		$	(219)
Other Derivatives:
Derivative instrument assets (1)	$	17		$	22
Derivative instrument liabilities (2)		(2)			(7)
Net asset	$	15		$	15

(1) Current, other and held for sale assets.

(2) Current, long-term and held for sale liabilities.

Realized and Unrealized Gains (Losses) Recognized in Net Income

	Three months ended				Nine months ended
For the	September 30				September 30
millions of dollars	2024		2023		2024		2023
Regulatory Deferral:
Regulated fuel for generation and purchased power (1)	$	(15)	$	6	$	(36)	$	70
HFT Derivatives:
Non-regulated operating revenues	$	59	$	90	$	209	$	907
Other Derivatives:
OM&G	$	22	$	(20)	$	8	$	(12)
Other income, net		5		(18)		(15)		-
Net gains (losses)	$	27	$	(38)	$	(7)	$	(12)
Total net gains	$	71	$	58	$	166	$	965

(1) Realized gains (losses) on derivative instruments settled and consumed in the period, hedging relationships that have been terminated or the hedged transaction is no longer probable. Realized gains (losses) recorded in inventory will be recognized in “Regulated fuel for generation and purchased power” when the hedged item is consumed.

As of September 30, 2024, the unrealized gain in accumulated other comprehensive income was $12 million, after-tax (December 31, 2023 – $14 million, after-tax). For the three and nine months ended September 30, 2024, unrealized gains of $1 million (2023 – $1 million) and $2 million (2023 – $2 million), respectively, have been reclassified into interest expense.

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DISCLOSURE AND INTERNAL CONTROLS

Management is responsible for establishing and maintaining adequate disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings. The Company’s internal control framework is based on criteria published in the Internal Control - Integrated Framework (2013), a report issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer, evaluated the design of the Company’s DC&P and ICFR as at September 30, 2024, to provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.

Management recognizes the inherent limitations in internal control systems, no matter how well designed. Control systems determined to be appropriately designed can only provide reasonable assurance with respect to the reliability of financial reporting and may not prevent or detect all misstatements.

There were no changes in the Company’s ICFR during the quarter ended September 30, 2024 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

CRITICAL ACCOUNTING ESTIMATES

The preparation of unaudited condensed consolidated interim financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. In Q3 2024, the Company recognized $210 million CAD ($155 million USD), pre-tax, in non-cash goodwill impairment related to the pending sale of NMGC. For more formation on the goodwill impairment, refer to note 19 in the condensed consolidated interim financial statements. There were no other material changes in the nature of the Company’s critical accounting estimates from those disclosed in Emera’s 2023 annual MD&A.

CHANGES IN ACCOUNTING POLICIES AND PRACTICES

Future Accounting Pronouncements

The Company considers the applicability and impact of all Accounting Standard Updates (“ASU”) issued by the Financial Accounting Standards Board (“FASB”). The following updates have been issued by the FASB, but as allowed, have not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be either not applicable to the Company or to have an insignificant impact on the consolidated financial statements.

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Disaggregation of Income Statement Expenses

In November 2024, the FASB issued ASU 2024-03, Income Statement Reporting–Comprehensive Income–Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard update improves the disclosures about a public business entity’s expenses by requiring more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation and amortization) included within income statement expense captions. The guidance will be effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The standard updates are to be applied prospectively with the option for retrospective application. The Company is currently evaluating the impact of adoption of the standard update on its consolidated financial statements disclosures.

Improvements to Income Tax Disclosures

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The standard enhances the transparency, decision usefulness and effectiveness of income tax disclosures by requiring consistent categories and greater disaggregation of information in the reconciliation of income taxes computed using the enacted statutory income tax rate to the actual income tax provision and effective income tax rate, as well as the disaggregation of income taxes paid (refunded) by jurisdiction. The standard also requires disclosure of income (loss) before provision for income taxes and income tax expense (recovery) in accordance with U.S. Securities and Exchange Commission Regulation S-X 210.4-08(h), Rules of General Application – General Notes to Financial Statements: Income Tax Expense, and the removal of disclosures no longer considered cost beneficial or relevant. The guidance will be effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted. The standard will be applied on a prospective basis, with retrospective application permitted. The Company is currently evaluating the impact of adoption of the standard on its consolidated financial statements disclosures.

Improvements to Reportable Segment Disclosures

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280), Improvements to Reportable Segment Disclosures. The change in the standard improves reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. The changes improve financial reporting by requiring disclosure of incremental segment information on an annual and interim basis for all public entities to enable investors to develop more decision-useful financial analyses. The guidance will be effective for annual reporting periods beginning after December 15, 2023, and for interim periods beginning after December 15, 2024. Early adoption is permitted. The standard will be applied retrospectively. The Company does not expect a material impact on its consolidated financial statements disclosures as a result of adoption of the standard.

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SUMMARY OF QUARTERLY RESULTS

For the quarter ended millions of dollars (except per share amounts)		Q3 2024		Q2 2024		Q1 2024		Q4 2023		Q3 2023		Q2 2023		Q1 2023		Q4 2022
Operating revenues	$	1,802	$	1,617	$	2,018	$	1,972	$	1,740	$	1,418	$	2,433	$	2,358
Net income attributable to common shareholders	$	4	$	129	$	207	$	289	$	101	$	28	$	560	$	483
Adjusted net income	$	236	$	151	$	216	$	175	$	204	$	162	$	268	$	249
EPS – basic	$	0.01	$	0.45	$	0.73	$	1.04	$	0.37	$	0.10	$	2.07	$	1.80
EPS – diluted	$	0.01	$	0.45	$	0.73	$	1.04	$	0.37	$	0.10	$	2.07	$	1.80
Adjusted EPS – basic	$	0.81	$	0.53	$	0.76	$	0.63	$	0.75	$	0.60	$	0.99	$	0.93

Quarterly operating revenues and adjusted net income are affected by seasonality. The first quarter provides strong earnings contributions due to a significant portion of the Company’s operations being in northeastern North America, where winter is the peak electricity usage season. The third quarter provides strong earnings contributions due to summer being the heaviest electric consumption season in Florida. Seasonal and other weather patterns, as well as the number and severity of storms, can affect demand for energy and the cost of service. Quarterly results could also be affected by items outlined in the “Significant Items Affecting Earnings” section.

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