6-K - EMA - Equibles

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER

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

UNDER THE SECURITIES EXCHANGE ACT OF 1934

For the month of November, 2025

Commission File Number: 001-42631

Emera Incorporated

(Exact name of registrant as specified in its charter)

5151 Terminal Road

Halifax NS B3J 1A1

Canada

(Address ofprincipal executive offices)

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

Form 20-F ☐ Form 40-F ☒

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

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

Exhibits 99.1, 99.2, 99.3, 99.4, 99.5 and 99.6 of this Form 6-K shall be incorporated by reference into the registration statement of Emera Incorporated on Form 40-F (File No. 001-42631).

SIGNATURES

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

	EMERA INCORPORATED
Date: November 7, 2025	By:	/s/ Brian Curry
		Name: Brian Curry<br> <br>Title: Corporate<br>Secretary

EXHIBIT INDEX

Exhibit No.	Description
99.1	Emera Incorporated Management’s Discussion and Analysis of financial position and results of operations as at and for the three month period ended September 30, 2025
99.2	Emera Incorporated Unaudited Condensed Consolidated Interim Financial Statements for the three month period ended September 30, 2025
99.3	Emera Incorporated Earnings Coverage Ratio for the twelve months ended September 30, 2025
99.4	Emera Incorporated Media Release dated September 30, 2025
99.5	Form 52-109F2 Certification of Interim Filings by the Chief Executive Officer
99.6	Form 52-109F2 Certification of Interim Filings by the Chief Financial Officer

EX-99.1

Exhibit 99.1

LOGO

Management’s Discussion & Analysis

As at November 7, 2025

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, 2025 relative to the same periods in 2024; and its financial position as at September 30, 2025 relative to December 31, 2024. 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, 2025; and the Emera annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2024. 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 and on EDGAR at www.sec.gov.

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, 2025, Emera’s rate-regulated subsidiaries and investments include:

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 Energy Board (“NSEB”), formerly Nova Scotia Utility and Review Board
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”)	NSEB
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
Wasoqonatl Transmission Incorporated (“WTI”)	NSEB

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.

TABLE OF CONTENTS

Forward-looking Information	2
Introduction and Strategic Overview	3
Non-GAAP Financial Measures and Ratios	4
Consolidated Financial Review	6
Significant Items Affecting Earnings	6
Consolidated Financial Highlights	7
Consolidated Income Statement Highlights	8
Business Overview and Outlook	10
Florida Electric Utility	10
Canadian Electric Utilities	11
Gas Utilities and Infrastructure	12
Other Electric Utilities	12
Other	13
Consolidated Balance Sheet Highlights	14
Other Developments	15
Financial Highlights	16
Florida Electric Utility	16
Canadian Electric Utilities	17
Gas Utilities and Infrastructure	18
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Other Electric Utilities	19
Other	20
Liquidity and Capital Resources	22
Consolidated Cash Flow Highlights	22
Contractual Obligations	24
Debt Management	25
Credit Ratings	26
Guarantees and Letters of Credit	26
Outstanding Stock Data	27
Transactions with Related Parties	28
Risk Management including Financial Instruments	28
Disclosure and Internal Controls	29
Critical Accounting Estimates	30
Changes in Accounting Policies and Practices	30
Future Accounting Pronouncements	30
Summary of Quarterly Results	32

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, the scope of the cybersecurity incident (the “Cybersecurity Incident”) and its expected impact on the Company’s financial position and results of operations, IT systems restoration, insurance recoveries, and business continuity processes as well as other matters relating to the Cybersecurity Incident, including 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; change in law risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; liquidity and capital markets 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; potential impacts of trade disputes and tariffs; estimated energy consumption rates; maintenance of adequate insurance coverage and receipt of proceeds; changes in customer energy usage patterns; developments in technology that could impact demand for electricity; climate change risk; 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; risks and costs associated with failure of information technology (“IT”) infrastructure and cybersecurity incidents including IT systems restoration and business continuity processes; uncertainties associated with infectious diseases, pandemics and similar public health threats; market energy sales prices; labour relations; and availability of labour and management resources.

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

Emera (TSX/NYSE: EMA) is a North American provider of energy services, owning and operating a portfolio of cost-of-service, rate-regulated electric and gas utilities. Its largest operations are in Florida, with additional operations in Atlantic Canada, New Mexico, and the Caribbean. Emera is headquartered in Halifax, Nova Scotia, Canada.

Emera’s business strategy is centred on continued investment in its regulated utilities, combined with a focus on operational excellence and efficiency, to safely and reliably deliver energy to its 2.7 million customers. Effective execution of these priorities supports predictable and growing earnings, cash flow and dividends for shareholders.

Earnings opportunities in regulated utilities are a function of the magnitude of net investment in the utility (known as “rate base”), the amount of equity in the capital structure, and the targeted return on that equity (“ROE”), all as established and approved through regulation. Earnings are also affected by sales volumes and operating expenses. In 2024, Emera’s regulated cost-of-service utilities in Florida accounted for 65 per cent of average consolidated rate base, with Atlantic Canada comprising 27 per cent, and the Caribbean and New Mexico at 4 per cent each.

Emera’s capital investment plan is forecasted to be approximately $20 billion from 2026 through 2030 and is focused on delivering value for customers through prudent investments in reliability and system resiliency, infrastructure modernization, expansion to address customer growth, integration of renewables, and technological innovations to deliver better customer experiences. It is anticipated that approximately 80 per cent of this capital investment will be made in Emera’s Florida utilities, necessitated by customer growth and system requirements at both TEC and PGS.

As at<br><br><br>millions of dollars		2026		2027		2028		2029		2030		Total
Capital investment plan	$	3,780	$	3,730	$	4,140	$	4,180	$	4,330	$	20,160
Average consolidated rate base<br>US operations	$	23,180	$	25,100	$	27,140	$	29,300	$	31,480
Canadian operations		7,340		7,660		7,990		8,320		8,580
Total	$	30,520	$	32,760	$	35,130	$	37,620	$	40,060

*Capital investment plan and average consolidated rate base exclude NMGC. Refer to “Other Developments” for more information on the pending sale of NMGC.

Emera’s capital investment plan will be funded primarily through internally generated cash flows, debt raised at the operating company level consistent with regulated capital structures, equity issuances, and proceeds from the anticipated sale of NMGC. Generally, Emera’s equity requirements are expected to be funded through the issuance of hybrid equity, and the issuance of common equity through Emera’s dividend reinvestment plan (“DRIP”) and its at-the-market program (“ATM program”). Maintaining investment-grade credit ratings is a core strategic priority of the Company.

Emera has increased dividends per common share paid for 19 consecutive years and has provided forward annual dividend growth guidance of one to two per cent. Emera anticipates adjusted EPS average growth of five to seven per cent through 2027 which will support reduction in the ratio of dividend payout to adjusted net income. 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.

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. These measures and ratios are discussed and reconciled below.

Adjusted Net Income,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 items below from net income attributable to common shareholders. Management believes excluding these items better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the business.

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 the “Financial Highlights – Gas Utilities and Infrastructure, Other Electric Utilities, and 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 the Company’s 2024 annual MD&A.

Mark-to-market (“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, and therefore excludes MTM adjustments for evaluation of performance and incentive compensation. The MTM adjustments are related to the following:

•	held-for-trading (“HFT”)<br>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<br>certain Emera Energy marketing and trading transactions;
•	the business activities of Bear Swamp Power Company LLC (“Bear Swamp”) included in Emera’s equity income;<br>
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•	equity securities held in BLPC and Emera Energy; and
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•	FX hedges entered into to hedge USD denominated operating unit earnings exposure.
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Charges Related to the Pending Sale of NMGC:

On August 5, 2024, Emera entered into an agreement to sell NMGC. In Q2 2025, the Company recognized a $71 million non-cash impairment charge, after-tax, and an additional loss of $1 million in estimated transaction costs, after-tax, related to the pending sale. 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. For further details, refer to the “Significant Items Affecting Earnings”, and “Other Developments” sections.

Gain on Sale of Emera’s IndirectMinority Interest in the Labrador Island Link (“Gain on sale of LIL”):

In Q2 2024, Emera recognized a $107 million gain, after tax and transaction costs, on the sale of LIL. For further details refer to the “Significant Items Affecting Earnings” section.

Reconciliation of Net IncomeAttributable to Common Shareholders to Adjusted Net Income

For the				Nine months ended<br>September 30
millions of dollars (except per share amounts)		2024		2025		2024
Net income attributable to common<br>shareholders	228	$	4	$	946	$	340
Less:Charges related to the pending sale of NMGC, after-tax (1)(2)	-		(225)	****	(72)		(225)
Gain on sale of LIL,<br>after-tax (3)	-		-	****	-		107
MTM (loss) gain, after-tax (4)	(35)		(7)	****	140		(145)
Adjusted net income	263	$	236	$	878	$	603
EPS – basic	0.76	$	0.01	$	3.17	$	1.18
Adjusted EPS – basic	0.88	$	0.81	$	2.94	$	2.10
(1) Represents (i) a 71 million non-cash impairment charge,<br>after-tax, and 1 million in transaction costs, after-tax for the nine months ended September 30, 2025 and (ii) 206 million in non-cash goodwill and other impairment charges, after-tax and 19 million in transaction costs, after-tax for the three and nine<br>months ended September 30, 2024.
(2) Net of income tax recovery of nil for the three months ended September 30, 2025 (2024 - 20 million) and 5 million for the nine months ended September 30, 2025 (2024 - 20<br>million).
(3) Net of income tax expense of 75 million for the nine months ended September 30, 2024.
(4) Net of income tax recovery of 15 million for the three months ended September 30, 2025 (2024 – 4 million recovery) and 56 million income tax expense for the<br>nine months ended September 30, 2025 (2024 – 60 million recovery).

All values are in US Dollars.

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. Adjusted EBITDA represents EBITDA absent the income effect of MTM adjustments, charges related to the pending sale of NMGC, and the 2024 gain on the sale of LIL.

Reconciliation of Net Income to EBITDA and Adjusted EBITDA*:*

For the	Three months ended<br>September 30				Nine months ended<br>September 30
millions of dollars	2025		2024		2025		2024
Net income (1)	$	248	$	23	$	1,003	$	395
Interest expense, net	****	260		241	****	764		725
Income tax (recovery) expense	****	6		(9)	****	116		40
Depreciation and amortization	****	324		293	****	959		866
EBITDA	$	838	$	548	$	2,842	$	2,026
Less:<br>Charges related to the pending sale of NMGC, excluding<br>income tax	****	-		(245)	****	(77)		(245)
Gain on sale of LIL, excluding income tax	****	-		-	****	-		182
MTM (loss) gain, excluding income tax	****	(50)		(11)	****	196		(205)
Adjusted EBITDA	$	888	$	804	$	2,723	$	2,294
(1) Net income is before Non-controlling interest in subsidiaries and Preferred stock dividends.

CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Earnings

Charges Related to the Pending Saleof NMGC

2025:

In Q2 2025, Emera recognized a non-cash impairment charge of $75 million ($71 million after-tax, or $0.24 per common share) related to the remeasurement of the NMGC disposal group to fair value (“FV”) less costs to sell. This was recorded in “Impairment charges” on the Condensed Consolidated Statements of Income and included in the Other segment.

2024:

In Q3 2024, Emera recognized non-cash goodwill and other impairment charges of $221 million ($206 million 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. Additionally, in Q3 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. These transaction costs were included in “Other income, net” on the Condensed Consolidated Statements of Income and included in the Other segment.

For further details on the pending sale of NMGC, refer to the “Other Developments” section. For further details on the non-cash impairment and goodwill charges, refer to note 3 in the condensed consolidated interim financial statements.

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

MTM loss, after-tax, increased $28 million to $35 million in Q3 2025, compared to $7 million in Q3 2024, primarily due to a loss on Corporate FX hedges compared to a gain in prior year. Year-to-date, the 2024 MTM loss, after-tax, of $145 million, decreased $285 million to a $140 million MTM gain, after-tax, for the same period in 2025, primarily due to favourable changes in existing positions and lower amortization of gas transportation assets at Emera Energy Services (“EES”).

2024 Gain on Sale of LIL

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, refer to note 3 in the condensed consolidated interim financial statements.

Consolidated Financial Highlights

For the<br> <br>millions of dollars	Three months ended<br>September 30				Nine months ended<br>September 30
Adjusted Net Income	2025		2024		2025		2024
Florida Electric Utility	$	302	$	252	$	726	$	524
Canadian Electric Utilities	****	13		26	****	151		155
Gas Utilities and Infrastructure	****	32		38	****	200		180
Other Electric Utilities	****	16		10	****	28		27
Other	****	(100)		(90)	****	(227)		(283)
Adjusted net income	$	263	$	236	$	878	$	603
Charges related to the pending sale of NMGC, after-tax	****	-		(225)	****	(72)		(225)
Gain on sale of LIL,<br>after-tax	****	-		-	****	-		107
MTM (loss) gain,<br>after-tax	****	(35)		(7)	****	140		(145)
Net income attributable to common<br>shareholders	$	228	$	4	$	946	$	340

The following table highlights significant quarter-over-quarter and year-over-year changes in adjusted net income from 2024 to 2025:

For the	Three months ended		Nine months ended
millions of dollars	September 30		September 30
Adjusted net income –2024	$	236	$	603
Operating Unit Performance
Increased earnings at TEC due to higher revenue from new base rates and customer growth, partially offset by increased operating, maintenance and general expenses (“OM&G”),<br>depreciation expense, interest and income tax expense. Year-over-year the increase was also due to the impact of favourable weather and the impact of a weaker CAD		50		202
Decreased income from equity investments due to the sale of LIL in Q2 2024		-		(28)
Increased earnings at EES year-over-year due to favourable weather and resulting market conditions in Q1 2025 (higher natural gas prices and increased volatility)		(1)		33
Increased earnings year-over-year at NMGC due to higher revenue from new base rates and the impact of a weaker CAD		(4)		22
Decreased earnings quarter-over-quarter at NSPI due to increased OM&G and higher depreciation expense. Increased earnings year-over-year due to investment tax credits<br>(“ITCs”) related to clean technology investments and increased sales volumes driven by favourable weather, partially offset by higher OM&G and higher depreciation expense		(11)		30
Corporate
Increased income tax recovery due to decreased deferred income tax asset valuation allowance and increased loss before provision for income taxes		11		18
Increased interest expense primarily due to increased total debt, partially offset by lower interest rates		(3)		(10)
Increased OM&G quarter-over-quarter and decreased year-over-year primarily due to timing of the recognition on long term compensation expense and related hedges		(16)		8
Other Variances		1		-
Adjusted net income –2025	$	263	$	878

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

For the	Nine months ended September 30
millions of dollars	2025		2024
Operating cash flow before changes in<br>working capital	$	1,972	$	1,732
Changes in working capital	****	(382)		220
Operating cash flow	$	1,590	$	1,952
Investing cash flow	$	(2,518)	$	(1,289)
Financing cash flow	$	941	$	(997)

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

As at	****	September 30		December 31
millions of dollars	****	2025		2024
Total assets	$	43,803	$	42,951
Total long-term debt (including<br>current portion) (1)	$	18,979	$	18,407
(1) Excludes NMGC balances classified as held for sale. For further details refer to the “Other Developments” section and note 3 in the<br>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)	2025		2024		Variance		2025		2024		Variance
Operating revenues	$	2,106	$	1,802	$	304	$	6,770	$	5,437	$	1,333
Operating expenses	****	1,626		1,586		(40)	****	5,070		4,596		(474)
Income from operations	$	480	$	216	$	264	$	1,700	$	841	$	859
Other income, net	$	19	$	14	$	5	$	135	$	232	$	(97)
Income tax expense (recovery)	$	6	$	(9)	$	(15)	$	116	$	40	$	(76)
Net income attributable to common<br>shareholders	$	228	$	4	$	224	$	946	$	340	$	606
Adjusted net income	$	263	$	236	$	27	$	878	$	603	$	275
Weighted average shares of common<br>stock outstanding (in millions)	****	299.9		290.0		9.9	****	298.5		287.5		11.0
EPS – basic	$	0.76	$	0.01	$	0.75	$	3.17	$	1.18	$	1.99
EPS – diluted	$	0.76	$	0.01	$	0.75	$	3.16	$	1.18	$	1.98
Adjusted EPS – basic	$	0.88	$	0.81	$	0.07	$	2.94	$	2.10	$	0.84
Dividends per common share<br>declared	$	0.7250	$	0.7175	$	0.0075	$	2.1750	$	2.1525	$	0.0225
Adjusted EBITDA	$	888	$	804	$	84	$	2,723	$	2,294	$	429

Operating Revenues

For Q3 2025, operating revenues increased $304 million compared to Q3 2024 and, excluding the change in MTM impacts, increased $316 million. The increase was due to higher storm cost recoveries at TEC and NSPI (offset in OM&G); new base rates at TEC and NMGC; higher regulatory deferral revenue at TEC; and the impact of a weaker CAD.

Year-to-date 2025, operating revenues increased $1,333 million compared to 2024 and, excluding the change in MTM impacts, increased $983 million. The increase was due to higher storm cost recoveries at TEC and NSPI (offset in OM&G); new base rates at TEC and NMGC; the impact of a weaker CAD; higher regulatory deferral revenue at TEC; increased marketing and trading margin at EES; favourable weather at NSPI and TEC; higher off-system sales at PGS; and customer growth at TEC.

Operating Expenses

For Q3 2025, operating expenses increased $40 million compared to Q3 2024. Excluding charges related to the pending sale of NMGC of $221 million recognized in 2024, operating expenses increased $261 million. Year-to-date operating expenses increased $474 million compared to 2024 and, excluding the change in charges related to the pending sale of NMGC of $146 million, increased $620 million. These increases were due to higher storm cost recognition at TEC and NSPI (offset in revenue); higher natural gas prices at TEC and PGS; increased depreciation at TEC, PGS and NMGC; and higher OM&G at NSPI, PGS and NMGC. The year-over-year increase was also due to the impact of a weaker CAD and higher regulated fuel for generation and purchase power and depreciation at NSPI.

Other Income, net

For Q3 2025, other income, net increased $5 million compared to Q3 2024 due to the 2024 transaction costs related to the pending sale of NMGC, partially offset by lower FX gains at Corporate in 2025.

Year-to-date, other income, net decreased $97 million compared to 2024 due to the gain on sale of LIL in 2024, partially offset by higher FX gains at Corporate in 2025, the 2024 transaction costs related to the pending sale of NMGC; and higher interest income at TEC.

Income Tax Expense (Recovery)

For Q3 2025, income tax expense increased $15 million compared to Q3 2024 due to the tax impact of lower charges related to the pending sale of NMGC, partially offset by decreased deferred income tax asset valuation allowance.

Year-to-date 2025, income tax expense increased $76 million compared to 2024 due to increased income before provision for income taxes (excluding the gain on sale of LIL in 2024 and charges related to the pending sale of NMGC) and the tax impact of lower charges related to the pending sale of NMGC. These were partially offset by the tax impact of the gain on sale of LIL in 2024; increased ITCs related to clean technology investments at NSPI; increased tax credits at TEC; and decreased deferred income tax asset valuation allowance.

Net Income and Adjusted Net Income

For Q3 2025, net income attributable to common shareholders, compared to Q3 2024, was favourably impacted by $225 million charges related to the pending sale of NMGC recognized in 2024 and unfavourably impacted by the $28 million increase in MTM losses. Excluding these impacts, adjusted net income increased $27 million, primarily due to increased earnings at TEC, partially offset by lower earnings at NSPI and NMGC and higher Corporate costs.

Year-to-date 2025, net income attributable to common shareholders, compared to the same period in 2024, was favourably impacted by the $285 million increase in MTM gain and the $153 million change in charges related to the pending sale of NMGC and unfavourably impacted by the $107 million gain on sale of LIL recognized in 2024. Excluding these changes, adjusted net income increased $275 million. The increase was primarily due to increased earnings at TEC, EES, NSPI and NMGC, and decreased Corporate costs. These were partially offset by lower equity earnings from LIL.

EPS – Basic and Adjusted EPS – Basic

For Q3 2025 and year-to-date, EPS – basic and adjusted EPS were higher due to increased earnings as discussed above, partially offset by the impact of an increase in weighted average shares outstanding.

Effect of Foreign Currency Translation

Results of foreign operations are translated at the weighted average rate of exchange, and assets and liabilities of foreign operations are translated at period end rates. For additional details on the effects of foreign currency translation, refer to the Company’s 2024 annual MD&A.

The relevant CAD/USD exchange rates for 2025 and 2024 are as follows:

	Three months ended<br>September 30				Nine months ended<br>September 30				Year ended<br>December 31
For the	2025		2024		2025		2024		2024
Weighted average CAD/USD	$	1.38	$	1.36	$	1.41	$	1.36	$	1.36
Period end CAD/USD exchange rate	$	1.39	$	1.35	$	1.39	$	1.35	$	1.44

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

						Nine months ended
For the						September 30
millions of			2024			2025			2024
Florida Electric Utility	220	****	$	186		$	522	****	$	385
Gas Utilities and Infrastructure (1)(2)	19	****		25		****	129	****		122
Other Electric Utilities	11	****		8		****	20	****		20
Other segment (3)	(47	)		(58	)	****	(97	)		(108	)
Total (2)(4)	203	****	$	161		$	574	****	$	419
(1) Includes adjusted net income from PGS, NMGC, SeaCoast and M&NP.
(2) Excludes 6 million after-tax in other impairment charges associated with the pending sale of NMGC for the three and nine months ended<br>September 30, 2024.
(3) Includes Emera Energy’s adjusted net income from EES, Bear Swamp and interest expense on Emera Inc.’s denominated debt.
(4) Excludes 20 million MTM loss, after-tax, for the three months ended September 30, 2025 (2024 – 183 million MTM loss,<br>after-tax) and 78 million MTM gain, after-tax, for the nine months ended September 30, 2025 (2024 – 272 million MTM loss, after-tax).

All values are in US Dollars.

The translation impact of a weaker CAD on USD earnings increased adjusted net income by $1 million in Q3 2025 and $16 million year-to-date, compared to the same periods in 2024. In Q3 2025, 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 $10 million decrease to net income attributable to common shareholders compared to the same period in 2024. Year-to-date 2025, the impact of a weaker CAD on US denominated earnings, increased net income attributable to common shareholders by $52 million, compared to the same period in 2024. 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 2024 annual MD&A, except for the updates disclosed below. The extent of the future impact of trade disputes and tariffs on the Company’s financial results and business operations continues to evolve, cannot be predicted at this time and will depend on future developments. To date, there has been no material financial impact on the Company. For information on risks associated with trade disputes and the imposition of tariffs, refer to the “Enterprise Risk and Risk Management” section in Emera’s 2024 annual MD&A.

Florida Electric Utility

TEC anticipates earning within the upper half of its ROE range in 2025. As a result of new base rates effective January 1, 2025, TEC’s 2025 USD earnings are expected to be higher than in 2024. TEC expects customer growth rates in 2025 to be comparable to 2024, reflective of the expected economic growth in Florida.

On September 4, 2025, TEC petitioned the FPSC to increase base revenue by $88 million USD to reflect the 2026 adjustment in accordance with its 2024 rate case decision. On November 4, 2025, the FPSC approved the adjustment, with new rates becoming effective January 1, 2026.

On February 3, 2025, the FPSC issued the final order approving the rate case decision, effective January 1, 2025. For additional details on the rate case decision, refer to note 7 in Emera’s 2024 annual audited consolidated financial statements. In February 2025, a motion for reconsideration on certain aspects of the final order was filed by an intervening party with the FPSC. On May 6, 2025, the FPSC denied the motion for reconsideration, except with respect to immaterial calculation corrections, and the final order was issued on June 11, 2025. In March 2025, two intervening parties each filed a notice of appeal to the Florida Supreme Court regarding the outcome of TEC’s 2024 base rate proceeding. To date, the intervening parties have not filed their briefs related to the appeal.

On February 4, 2025, the FPSC approved TEC’s petition for the recovery of $466 million USD of costs associated with Hurricane Idalia, Hurricane Debby, Hurricane Helene and Hurricane Milton, and the associated interest to replenish the storm reserve over an 18-month recovery period, which began in March 2025. The amount of cost-recovery is subject to a true-up mechanism with the FPSC. For additional details on the storm reserve, refer to note 7 in Emera’s annual audited consolidated financial statements.

In 2025, capital investment in the Florida Electric Utility segment is expected to be $1.7 billion USD (2024 – $1.4 billion USD), including allowance for funds used during construction (“AFUDC”). Capital projects include solar investments, storm hardening investments, grid modernization, and building resilience.

Canadian Electric Utilities

NSPI

NSPI anticipates earning below its allowed ROE range in 2025. NSPI expects earnings in 2025 to be lower than 2024, primarily due to higher operating costs related to the Cybersecurity Incident. Sales volumes are expected to be higher in 2025 than 2024.

On September 18, 2025, NSPI filed a consensus General Rate Application (“GRA”) with the NSEB, reflecting a settlement agreement reached with customer representatives. The settlement reflects more than six months of discussion, consultation, and information sharing. The GRA proposes average annual rate increases of 1.8 per cent in 2026 and 2.4 per cent in 2027. The proposed rates would result in annual revenue (fuel and non-fuel) increases of $62 million in 2026 and $108 million in 2027. The hearing for the matter is scheduled for January 2026 and a decision by the NSEB is expected in Q1 2026.

On March 5, 2025, NSPI, the Canada Infrastructure Bank (“CIB”) and the Wskijinu’k Mtmo’taqnuow Agency (“WMA”) announced the Wasoqonatl transmission line project to create a reliability intertie between Nova Scotia and New Brunswick. The project will be owned by a new regulated utility, WTI, which is wholly-owned by a newly formed limited partnership between NSPI, CIB and WMA. NSPI will be responsible for providing construction, operation, maintenance and administrative services to WTI. NSPI has a 50 per cent indirect voting interest in WTI which will be recorded as “Investments subject to significant influence” on Emera’s Consolidated Balance Sheets. As of September 30, 2025, NSPI’s investment is nominal.

In 2025, capital investment, including AFUDC, is expected to be $700 million (2024 – $487 million). NSPI is primarily investing in capital projects required to support power system reliability and reliable service for customers.

NSPML

Equity earnings from NSPML in 2025 are expected to be consistent with 2024. The NSPML investment is recorded as “Investments subject to significant influence” on Emera’s Consolidated Balance Sheets.

On July 18, 2025, NSPML submitted an application to the NSEB requesting recovery of approximately $199 million in Maritime Link costs for 2026. A decision is expected in Q4 2025.

On November 29, 2024, NSPML received approval from the NSEB to collect up to $197 million in 2025 from NSPI. Payments from NSPI are subject to a holdback of up to $4 million per month. There was no holdback recorded year-to-date in 2025. NSPML expects to file an application to terminate the holdback mechanism by early 2026.

NSPML does not anticipate any significant capital investment in 2025.

Gas Utilities and Infrastructure

PGS

PGS anticipates earning at the bottom of its allowed ROE range in 2025. USD earnings for 2025 are expected to be consistent with 2024.

On March 31, 2025, PGS filed a rate case with the FPSC for new rates to become effective January 1, 2026. On August 13, 2025, PGS and the intervening parties filed a settlement agreement with the FPSC for a $67 million USD increase in 2026 annual base rates, which includes $7 million USD from the cast iron and bare steel replacement rider, and additional adjustments of $25 million USD in 2027 and up to $5 million USD in 2028 (subject to FPSC approval). This reflects a 10.30 per cent midpoint ROE and 54.7 per cent equity thickness. On October 31, 2025, the FPSC issued the final order approving the settlement, effective January 1, 2026.

In 2025, capital investment, including AFUDC, is expected to be approximately $330 million USD (2024 – $323 million USD). PGS is investing to maintain the reliability of its system and support customer growth.

NMGC

On August 5, 2024, Emera announced an agreement to sell NMGC. As a result of the pending sale, NMGC’s assets and liabilities were classified as held for sale beginning in Q3 2024. In July 2025, the procedural schedule for the NMPRC regulatory process was revised with the public hearing rescheduled from June 2025 to November 2025. The transaction is expected to close in early 2026. For more information on the pending transaction, refer to the “Other Developments” section.

As a result of the change in expected timing of the pending sale, NMGC’s USD earnings contribution in 2025 are expected to be slightly higher than the adjusted USD earnings in 2024 due to higher revenue from new base rates.

OtherElectric Utilities

Other Electric Utilities’ USD earnings in 2025 are expected to be consistent with the prior year.

In 2025, capital investment in the Other Electric Utilities segment is expected to be approximately $70 million USD, including AFUDC (2024 – $59 million USD), primarily in projects to support system reliability.

GBPC

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 (“URCA”), another Bahamian regulator, regulate GBPC. URCA filed a claim in the Supreme Court of the Bahamas, seeking an order that the GBPA be prohibited and restrained from considering and/or approving any adjustment to rates sought by GBPC. URCA contends that it has regulatory authority over electricity provision on Grand Bahama pursuant to the Electricity Act. Management does not expect that the outcome of the proceedings will have a material impact to Emera.

Other

The adjusted net loss from the Other segment is expected to be lower in 2025 than 2024, due to higher contributions from EES and the wind down of Block Energy LLC in Q4 2024.

Earnings from EES are generally dependent on market conditions. In particular, volatility in natural gas and electricity markets, which can be influenced by weather, local supply constraints and other supply and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1 and Q4 usually providing the greatest opportunity for earnings. EES is generally expected to deliver annual adjusted net income of $15 to $30 million USD. In light of a strong performance in Q1, EES expects adjusted net income between $35 and $45 million USD in 2025.

The Other segment does not anticipate any significant capital investment in 2025.

CONSOLIDATED BALANCE SHEET HIGHLIGHTS

Significant changes in the Consolidated Balance Sheets between December 31, 2024 and September 30, 2025 include:

millions of dollars	Total<br>Increase<br>(Decrease)		Explanation of Increase (Decrease)
Assets
Inventory	$	69	Increased due to higher natural gas prices and volumes at EES, and higher volumes of materials inventory at NSPI
Derivative instruments (current and long-term)	****	103	Increased due to reversal of 2024 contracts at EES, and changes in FX hedges at Corporate
Regulatory assets (current and long-term)	****	(195)	Decreased due to lower storm cost recovery assets at TEC and NSPI and the effect of FX translation of Emera’s non-Canadian affiliates. These<br>were partially offset by higher deferrals related to the fuel adjustment mechanism (“FAM”) and deferred income tax regulatory asset at NSPI
Receivables and other assets (current and long-term)	****	395	Increased due to higher operating revenue at TEC and timing of accounts receivable at NSPI. These were partially offset by decreased cash collateral positions on derivative instruments at<br>EES and NSPI
Assets held for sale (current and long-term), net of liabilities (1)	****	(109)	Decreased primarily due to non-cash impairment charge recognized in 2025, lower accounts receivable due to seasonal trends of the business, and the<br>effect of FX translation at NMGC
PP&E, net of accumulated depreciation and amortization	****	832	Increased due to capital additions in excess of depreciation, partially offset by the effect of FX translation of Emera’s non-Canadian<br>affiliates
Goodwill	****	(191)	Decreased due to the effect of FX translation of Emera’s non-Canadian affiliates
Liabilities and Equity
Short-term debt and long-term debt (including current portion)	$	837	Increased due to issuance of long-term debt at TEC, and proceeds from issuance of a non-revolving term credit facility at NSPI. These were partially<br>offset by the effect of FX translation of Emera’s non-Canadian affiliates and repayment of committed credit facilities at TEC and PGS
Accounts payable	****	(179)	Decreased due to lower storm cost payments at TEC, lower commodity prices at EES and the effect of FX translation of Emera’s non-Canadian<br>affiliates. These were partially offset by timing of accounts payable at NSPI
Deferred income tax liabilities, net of deferred income tax assets	****	108	Increased due to tax deductions in excess of accounting depreciation related to PP&E. This was partially offset by increased tax credits at TEC and the effect of FX translation of<br>Emera’s non-Canadian affiliates
Derivative instruments (current and long-term)	****	(70)	Decreased due to reversal of 2024 contracts and changes in existing positions at EES and changes in FX hedges at Corporate. These were partially offset by new contracts at EES
Regulatory liabilities (current and long-term)	****	(179)	Decreased due to lower FAM liability at NSPI, cost recovery clause liabilities and decreased deferred income tax regulatory liability at TEC, and the effect of FX translation of<br>Emera’s non-Canadian affiliates
Other liabilities (current and long-term)	****	168	Increased due to timing of interest payments at Corporate, timing of property tax payments at TEC, and accrued output-based pricing system (“OBPS”) carbon tax and increased<br>customer deposits at NSPI
Common stock	****	270	Increased due to shares issued
Accumulated other comprehensive income	****	(376)	Decreased due to the effect of FX translation of Emera’s non-Canadian affiliates
Retained earnings	****	298	Increased due to net income in excess of dividends paid

(1) On August 5, 2024, Emera announced the sale of NMGC. As a result, NMGC’s assets and liabilities were classified as held for sale beginning in Q3 2024. For further details, refer to the ‘Other Developments’ section and note 3 in the condensed consolidated interim financial statements.

OTHER DEVELOPMENTS

Increase in Common Dividend

On September 25, 2025, the Emera Board of Directors approved an increase in the annual common share dividend rate to $2.93 from $2.90 per common share. The first payment will be effective November 14, 2025.

Cybersecurity Incident

On April 25, 2025, Emera and NSPI discovered a Cybersecurity Incident involving unauthorized access into certain parts of its Canadian network and servers supporting portions of its business applications. Immediately following detection of the external threat, incident response and business continuity protocols were activated, including the engagement of leading third-party cybersecurity experts. Actions were taken to contain and isolate the affected servers and prevent further intrusion and to notify law enforcement in Canada and the United States (“US”). There was no disruption to any of the Company’s Canadian physical operations, including at NSPI’s generation, transmission and distribution facilities, the Maritime Link, or the Brunswick Pipeline. There was no impact to Emera’s US or Caribbean utilities’ operations. The post-incident investigation is nearing completion.

The Company implemented business continuity processes for certain impacted business and administrative functions at its Canadian affiliates. The systematic restoration of affected IT systems and corresponding transition away from business continuity processes is progressing and will continue in a planned, controlled and phased approach. For more information on the impact on internal controls over financial reporting, refer to the “Disclosure and Internal Controls” section. The Company maintains cyber insurance coverage and is working with its insurer on the claims process. At this time, the Cybersecurity Incident is not expected to have a material impact on the Company’s financial position or results of operations. For information on risks associated with cybersecurity incidents generally, refer to the “Enterprise Risk and Risk Management” section of Emera’s annual 2024 MD&A.

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. As a result of the pending sale, NMGC’s assets and liabilities were classified as held for sale in Q3 2024 and the carrying value of the assets and liabilities were adjusted to FV less cost to sell. In July 2025, the procedural schedule for the NMPRC regulatory process was revised with the public hearing rescheduled from June 2025 to November 2025. The transaction is expected to close in early 2026.

At each reporting date, the Company performs an assessment of the FV of the disposal group by comparing the FV of expected transaction proceeds, less costs to sell, to the carrying value of net assets, including goodwill (“carrying amount”). On June 30, 2025, the Company remeasured the NMGC disposal group at the lower of its carrying amount and FV less costs to sell. As a result of the change in the expected timing of the transaction close, a non-cash impairment charge of $75 million ($71 million, after-tax), or $55 million USD ($52 million USD, after-tax), was recorded in “Impairment charges” on the Condensed Consolidated Statements of Income in Q2 2025. An additional loss for estimated future transaction costs of $2 million ($1 million after-tax) was recorded in “Other income, net” on the Condensed Consolidated Statements of Income in Q2 2025. There were no additional adjustments recorded in Q3 2025 as a result of the FV less cost to sell assessment performed as at September 30, 2025.

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 $79 million ($57 million USD) was recorded on these assets from August 5, 2024, the date they were classified as held for sale, through September 30, 2025. Of the $79 million ($57 million USD) recorded to date, $53 million ($38 million USD) was recorded in 2025.

US One Big Beautiful Bill Act (“OBBBA”)

On July 4, 2025, the OBBBA was signed into law. The OBBBA makes permanent many of the expired and expiring tax provisions originally enacted in the Tax Cuts and Jobs Act of 2017. It also includes significant changes in future years to the timing and availability of several clean energy tax credits previously enacted in the Inflation Reduction Act, including the investment tax credit and production tax credit. On August 15, 2025, the Internal Revenue Service released guidance on determining when wind and solar projects have begun construction for purposes of qualifying for these tax credits. Emera is currently evaluating the impact of the enacted changes but does not anticipate a material impact on the Company.

New York Stock Exchange (“NYSE”) Listing

Emera filed a registration statement dated May 1, 2025 on Form 40-F with the US Securities and Exchange Commission (“SEC”) to register its common shares under Section 12 of the Securities Exchange Act of 1934. Emera subsequently completed the listing of its common shares on the NYSE and commenced trading on May 28, 2025. Emera’s common shares continue to be listed and traded on the Toronto Stock Exchange.

Appointments

Executive

Effective December 1, 2025, Jared Green will become Emera’s new Chief Financial Officer, succeeding Greg Blunden. Mr. Green most recently served as President and Chief Executive Officer of TriSummit Utilities (previously AltaGas Canada).

Board of Directors

Effective September 17, 2025, Isabelle Courville joined the Emera Board of Directors. Ms. Courville is Chair of the Board of Canadian Pacific Kansas City and previously served as President of Hydro-Québec Distribution and Hydro Québec TransÉnergie, as well as President of Bell Canada’s Enterprise Group.

FINANCIAL HIGHLIGHTS

Florida Electric Utility

For the	Three months ended<br>September 30				Nine months ended<br>September 30
millions of USD (except as indicated)	2025		2024		2025		2024
Operating revenues – regulated<br>electric	$	921	$	724	$	2,409	$	1,944
Regulated fuel for generation and<br>purchased power	$	204	$	164	$	553	$	471
Contribution to consolidated net<br>income	$	220	$	186	$	522	$	385
Contribution to consolidated net<br>income – CAD	$	302	$	252	$	726	$	524
Electric sales volumes (Gigawatt hours<br>(“GWh”))	****	6,270		6,437	****	16,306		16,080
Electric production volumes<br>(GWh)	****	6,589		6,661	****	17,150		17,017
Average fuel cost in dollars per<br>megawatt hour (“MWh”)	$	31	$	25	$	32	$	28

The impact of the change in FX rates increased CAD earnings for the three and nine months ended September 30, 2025, by $3 million and $16 million, respectively.

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

For the		Nine months ended
millions of		September 30
Contribution to consolidated net<br>income – 2024	186	$	385
Increased operating revenues primarily due to new base rates, storm cost recovery revenue (offset in OM&G), higher regulatory deferral revenue and customer growth. Year-over-year the<br>increase was also due to the impact of favourable weather (20 million)	197		465
Increased fuel for generation and purchased power due to higher natural gas prices and higher purchased power	(40)		(82)
Increased OM&G due to higher storm cost recognition (offset in revenue), and higher costs for employee benefits; operations related to solar investments; and software maintenance. These<br>were partially offset by the timing of recognition of regulatory deferrals	(86)		(158)
Increased depreciation and amortization due to facilities and capital projects placed in service	(13)		(34)
Increased interest expense due to higher borrowings	(8)		(16)
Increased income tax expense primarily due to higher income before provision for income taxes, partially offset by increased amortization of deferred ITCs. Year-over-year the increase was<br>also partially offset by higher benefit from production tax credits	(10)		(34)
Other	(6)		(4)
Contribution to consolidated net<br>income – 2025	220	$	522

All values are in US Dollars.

Canadian Electric Utilities

	Three months ended				Nine months ended
For the	September 30				September 30
millions of dollars (except as indicated)	2025		2024		2025		2024
Operating revenues – regulated<br>electric	$	405	$	399	$	1,440	$	1,376
Regulated fuel for generation and<br>purchased power (1)	$	222	$	243	$	796	$	725
Contribution to consolidated net<br>income	$	13	$	26	$	151	$	155
Electric sales volumes (GWh)	****	2,230		2,285	****	7,936		7,849
Electric production volumes<br>(GWh)	****	2,380		2,428	****	8,466		8,361
Average fuel costs in dollars per<br>MWh	$	93	$	100	$	94	$	87

(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.

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	2025		2024		2025		2024
NSPI	$	3	$	14	$	119	$	89
Equity investment in NSPML	****	10		12	****	32		38
Equity investment in LIL (1)	****	-		-	****	-		28
Contribution to consolidated netincome	$	13	$	26	$	151	$	155

(1) On June 4, 2024, Emera completed the sale of LIL. For further details, refer to note 3 in the condensed consolidated interim financial statements.

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 netincome – 2024	$	26	$	155
Increased operating revenue at NSPI due to higher fuel and storm cost recoveries, partially offset by lower industrial sales volumes. Year-over-year increase also due to favourable weather<br>and increased residential and commercial sales volumes		6		64
Decreased regulated fuel for generation and purchased power quarter-over-quarter due to lower commodity prices, partially offset by higher Maritime Link assessment costs. Year-over year<br>increased due to changes in generation mix, increased Maritime Link assessment costs, higher sales volumes, and higher Nova Scotia OBPS carbon tax, partially offset by lower commodity prices		21		(71)
Decreased FAM quarter-over-quarter due to lower under-recovery of fuel costs. Year-over-year increased due to higher under-recovery of fuel costs		(25)		39
Increased OM&G at NSPI due to higher costs for transmission and distribution operations, and power generation operations, partially offset by higher administrative overhead allocated to<br>property, plant and equipment (“PP&E”). Year-over-year increase was also due to costs related to the Cybersecurity Incident, partially offset by lower storm restoration costs		(11)		(28)
Increased depreciation and amortization due to increased PP&E in service		(3)		(12)
Decreased income from equity investments due to the sale of LIL		-		(28)
Increased income tax recovery year-over-year primarily due to clean technology ITCs in 2025		1		39
Other		(2)		(7)
Contribution to consolidated netincome – 2025	$	13	$	151

Gas Utilities and Infrastructure

					Nine months ended
For the					September 30
millions of (except as indicated)		2024			2025		2024
Operating revenues – regulated<br>gas (1)	227	$	216		$	908	$	843
Operating revenues – non-regulated	5		5		****	13		12
Total operating revenue	232	$	221		$	921	$	855
Regulated cost of natural gas	39	$	34		$	245	$	208
Contribution to consolidated adjusted<br>net income	23	$	28		$	141	$	133
Contribution to consolidated adjusted<br>net income – CAD	32	$	38		$	200	$	180
Charges related to the pending sale of<br>NMGC, after-tax (2)	-		(6	)	****	-		(6	)
Contribution to consolidated net<br>income	23	$	22		$	141	$	127
Contribution to consolidated net<br>income – CAD	32	$	30		$	200	$	172
Gas sales volumes (millions of<br>Therms)	743		729		****	2,359		2,370
(1) Operating revenues – regulated gas includes 11 million of finance income from Brunswick Pipeline (2024 – 11 million) for the<br>three months ended September 30, 2025 and 34 million (2024 – 34 million) for the nine months ended September 30, 2025.
(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.

All values are in US Dollars.

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	2025		2024		2025		2024
PGS	$	21	$	24	$	86	$	92
NMGC	****	(6)		(3)	****	30		16
Other	****	8		7	****	25		25
Contribution to consolidatedadjusted net income	$	23	$	28	$	141	$	133

The impact of the change in FX rates was minimal for the three months ended September 30, 2025, and increased CAD earnings for the nine months ended September 30, 2025 by $8 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 consolidatednet income – 2024	$	22	$	127
Increased gas revenues due to higher fuel revenue and off-system sales at PGS and new base rates at NMGC		11		66
Increased cost of natural gas due to higher natural gas prices at PGS and NMGC		(5)		(37)
Increased OM&G primarily due to higher labour costs at PGS and NMGC, partially offset by the timing of deferred clause recoveries at PGS		(6)		(4)
Increased depreciation primarily due to capital projects placed in service at PGS and NMGC		(4)		(10)
Other		5		(1)
Contribution to consolidated net income – 2025	$	23	$	141

Other Electric Utilities

	Three months ended				Nine months ended
For the	September 30				September 30
millions of USD (except as indicated)	2025		2024		2025		2024
Operating revenues – regulated<br>electric	$	115	$	110	$	311	$	306
Regulated fuel for generation and<br>purchased power	$	60	$	58	$	160	$	160
Contribution to consolidated adjusted<br>net income	$	11	$	8	$	20	$	20
Contribution to consolidated adjusted<br>net income – CAD	$	16	$	10	$	28	$	27
Equity securities MTM gain	$	-	$	-	$	1	$	1
Contribution to consolidated net<br>income	$	11	$	8	$	21	$	21
Contribution to consolidated net<br>income – CAD	$	16	$	11	$	30	$	29
Electric sales volumes (GWh)	****	349		346	****	977		984
Electric production volumes<br>(GWh)	****	377		371	****	1,045		1,056
Average fuel costs in dollars per<br>MWh	$	159	$	156	$	153	$	152

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

				Nine months ended
For the				September 30
millions of		2024		2025		2024
BLPC	6	$	4	$	12	$	14
C	6		4	****	9		8
Other	(1)		-	****	(1)		(2)
Contribution to consolidated<br>adjusted net income	11	$	8	$	20	$	20

All values are in British Pounds.

The impact of the change in FX rates on CAD earnings and adjusted net income for the three and nine months ended September 30, 2025 was minimal.

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

For the		Nine months ended
millions of		September 30
Contribution to consolidated<br>net income – 2024	8	$	21
Increased operating revenues – regulated electric due to higher fuel revenue at C and higher miscellaneous revenue at BLPC	5		5
Increased regulated fuel for generation and purchased power due to higher fuel costs at C	(2)		-
Increased income tax expense due to the remeasurement of deferred income tax liabilities as a result of a corporate income tax rate change at BLPC	-		(2)
Other	-		(3)
Contribution to consolidated net<br>income – 2025	11	$	21

All values are in British Pounds.

Other

	Three months ended				Nine months ended
For the	September 30				September 30
millions of dollars	2025		2024		2025		2024
Marketing and trading margin<br>(1)(2)	$	(3)	$	(7)	$	98	$	42
Other non-regulated<br>operating revenue	****	9		7	****	25		22
Total operating revenues – non-regulated	$	6	$	-	$	123	$	64
Contribution to consolidated adjusted<br>net (loss) income	$	(100)	$	(90)	$	(227)	$	(283)
Charges related to the pending sale<br>of NMGC, after-tax (3)	****	-		(217)	****	(72)		(217)
Gain on sale of LIL,<br>after-tax (4)(5)	****	-		-	****	-		107
MTM (loss) gain, after-tax<br>(6)	****	(35)		(8)	****	138		(147)
Contribution to consolidated net<br>(loss) income	$	(135)	$	(315)	$	(161)	$	(540)

(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, 2025 (2024 – $37 million loss) and a gain of $160 million for the nine months ended September 30, 2025 (2024 – $198 million loss).

(3) Includes an impairment charge of $75 million ($71 million after-tax) and transaction costs of $2 million ($1 million after-tax) for the nine months ended September 30, 2025, and impairment charges 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.

(4) On June 4, 2024, Emera completed the sale of its LIL equity interest. For further details on the transaction, refer to note 3 in the condensed consolidated interim financial statements.

(5) Net of income tax expense of $75 million for the nine months ended September 30, 2024.

(6) Net of income tax recovery of $15 million for the three months ended September 30, 2025 (2024 – $4 million recovery) and $56 million income tax expense for the nine months ended September 30, 2025 (2024 – $60 million recovery).

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	2025		2024		2025		2024
Emera Energy
EES	$	(8)	$	(7)	$	47	$	14
Other	****	(1)		2	****	(5)		4
Corporate – see breakdown of contribution below	****	(96)		(82)	****	(274)		(287)
Block Energy LLC	****	5		(3)	****	6		(13)
Other	****	-		-	****	(1)		(1)
Contribution to consolidatedadjusted net (loss) income	$	(100)	$	(90)	$	(227)	$	(283)

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 – 2024	$	(315)	****	$	(540)	****
Increased marketing and trading margin due to favourable weather conditions that led to higher natural gas prices and increased volatility that created profitable opportunities		4			56
Increased OM&G quarter-over-quarter primarily due to a lower gain on the long-term incentive hedge. Decreased year-over-year due to a higher gain on the long-term incentive hedge,<br>partially offset by higher long-term compensation expense and increased consulting costs		(18	)		6
Decreased equity earnings at Bear Swamp due to lower generation as a result of an outage		(4	)		(14	)
Increased interest expense primarily due to increased total debt, partially offset by decreased interest rates		(3	)		(10	)
Increased income tax recovery quarter-over-quarter due to decreased deferred income tax asset valuation allowance and increased loss before provision for income taxes. Increased income tax<br>recovery year-over-year due to decreased deferred income tax asset valuation allowance and a favourable tax impact of foreign currency translation, partially offset by decreased loss before provision for income taxes		9			5
Charges related to the pending sale of NMGC, after-tax		217			145
Gain on sale of LIL, after-tax		-			(107	)
Increased MTM loss, after-tax, quarter-over-quarter due primarily to a loss on Corporate FX hedges compared to a gain in prior year. Decreased MTM<br>loss, after-tax, year-over-year primarily due to favourable changes in existing positions and lower amortization of gas transportation assets at EES		(27	)		285
Other		2			13
Contribution to consolidated net(loss) income – 2025	$	(135	)	$	(161	)

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	2025		2024		2025		2024
Operating expenses (1)	$	(16)	$	-	$	(43)	$	(51)
Interest expense	****	(93)		(90)	****	(280)		(270)
Income tax recovery	****	38		27	****	112		94
Preferred dividends	****	(19)		(18)	****	(56)		(54)
Other (2)(3)	****	(6)		(1)	****	(7)		(6)
Corporate adjusted net loss(4)(5)(6)	$	(96)	$	(82)	$	(274)	$	(287)

(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 $2 million ($2 million after-tax) for the three months ended September 30, 2025 (2024 – $3 million net loss, pre-tax and $2 million loss, after-tax) and a $12 million net loss, pre-tax ($9 million after-tax) for the nine months ended September 30, 2025 (2024 – $7 million net loss, pre-tax and $5 million loss, after-tax) on FX hedges, as discussed above.

(4) Excludes a MTM loss, after-tax, of $10 million for the three months ended September 30, 2025 (2024 – $6 million gain, after-tax) and a MTM gain, after-tax of $23 million for the nine months ended September 30, 2025 (2024 – $6 million loss, after-tax).

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

(6) Excludes certain charges related to the pending sale of NMGC of $77 million ($72 million after-tax) for the nine months ended September 30, 2025, and $234 million ($217 million after-tax) for the three and nine months ended September 30, 2024.

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 $20 billion capital investment plan over the 2026 through 2030 period and supports ongoing growth. Capital investments at Emera’s regulated utilities are subject to regulatory approval.

Emera has sufficient liquidity to service debt obligations as they come due to meet any near-term capital investment requirements as currently planned. Emera plans to use cash from operations, debt raised at the utilities, Corporate equity, and proceeds from 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, Corporate equity requirements in support of the Company’s capital investment plan are expected to be funded through issuance of hybrid 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 $640 million CAD and $834 million USD undrawn and available at September 30, 2025. The Company was holding a cash balance of $215 million, which includes $3 million classified as assets held for sale, related to the pending sale of NMGC, at September 30, 2025. For further discussion, refer to the “Debt Management” section below.

Consolidated Cash Flow Highlights

Significant changes in the Condensed Consolidated Statements of Cash Flows between the nine months ended September 30, 2025 and 2024 include:

millions of dollars	2025		2024		Change
Cash, cash equivalents, restricted cash, and cash associated with assets held for sale, beginning of period	$	221	$	588	$	(367)
Provided by (used in):
Operating cash flow before changes in working capital	****	1,972		1,732		240
Changes in non-cash working<br>capital	****	(382)		220		(602)
Operating activities	$	1,590	$	1,952	$	(362)
Investing activities	****	(2,518)		(1,289)		(1,229)
Financing activities	****	941		(997)		1,938
Effect of exchange rate changes on cash, cash equivalents, restricted cash, and cash associated with assets held for sale	****	(5)		10		(15)
Cash, cash equivalents, restricted cash and cash associated with assets held for sale, end of period	$	229	$	264	$	(35	)

Cash Flow from Operating Activities

Net cash provided by operating activities decreased $362 million to $1,590 million for the nine months ended September 30, 2025, compared to $1,952 million for the same period in 2024.

Cash from operations before changes in working capital increased $240 million year-over-year. This increase was due to new base rates at TEC and NMGC, higher storm cost recoveries at TEC, higher marketing and trading margin at EES, and higher fuel over-recoveries at PGS. These were partially offset by proceeds from the FAM asset sale at NSPI in Q2 2024 and higher fuel under-recoveries at TEC.

Changes in non-cash working capital decreased operating cash flow by $602 million year-over-year. This decrease was due to unfavourable changes in accounts payable at TEC due to the timing and payment of storm invoices, unfavourable changes in accounts receivable at TEC due to increased base rates and storm cost recoveries, unfavourable changes in accounts receivable and inventory at NSPI and the recognition of ITCs related to clean technology investments at NSPI. These were partially offset by timing of accounts receivable at PGS and timing of accounts payable at PGS and NSPI.

Cash Flow from Investing Activities

Net cash used in investing activities increased $1,229 million to $2,518 million for the nine months ended September 30, 2025, compared to $1,289 million for the same period in 2024. The increase was due to the proceeds of $927 million received in 2024 on the sale of LIL and higher capital investment, partially offset by proceeds on the disposal of assets.

Capital investments, including AFUDC, for the nine months ended September 30, 2025, were $2,615 million, compared to $2,259 million for the same period in 2024. Details of the 2025 capital investment by segment are shown below:

•	$1,616 million – Florida Electric Utility (2024 – $1,375 million);
•	$491 million – Canadian Electric Utilities (2024 – $389 million);
---	---
•	$444 million – Gas Utilities and Infrastructure (2024 – $437 million);
---	---
•	$63 million – Other Electric Utilities (2024 – $54 million); and
---	---
•	$1 million – Other (2024 – $4 million).
---	---

Cash Flow from Financing Activities

Net cash provided by financing activities increased $1,938 million to $941 million for the nine months ended September 30, 2025, compared to cash used in financing activities of $997 million for the same period in 2024. This increase was due to lower net repayments under committed credit facilities at Emera and TEC, proceeds from short-term debt at NSPI, higher net borrowings on committed credit facilities at NSPI and NMGC, retirement of long-term debt at Emera US Finance LP, TEC and NMGC in 2024 and higher proceeds from long-term debt at TEC. These were partially offset by the 2024 issuance of long-term debt at EUSHI Finance Inc. (“EUSHI Finance”), higher repayments of short-term debt at TECO Finance Inc, lower issuance of common stock, and retirement of long-term debt at NSPI.

Contractual Obligations

As at September 30, 2025, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:

millions of dollars	2025		2026		2027		2028		2029		Thereafter		Total
Long-term debt principal<br>(1)(2)	$	17	$	1,282	$	89	$	834	$	2,190	$	15,374	$	19,786
Interest payment obligations (3)(4)		344		937		907		902		811		14,002		17,903
Purchased power (5)		89		316		406		396		445		5,951		7,603
Transportation (6)(7)		241		725		578		466		407		3,122		5,539
Fuel, gas supply and storage (8)		227		660		130		45		40		99		1,201
Capital projects		342		149		40		5		2		-		538
Pension and post-retirement obligations (9)		8		32		67		71		71		219		468
Asset retirement obligations		10		3		3		5		3		432		456
Other		42		72		58		50		48		264		534
	$	1,320	$	4,176	$	2,278	$	2,774	$	4,017	$	39,463	$	54,028

As detailed below, contractual obligations at September 30, 2025 includes those related to NMGC. On completion of the sale of NMGC, all 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 $673 million related to NMGC (2026: $97 million and $576 million thereafter).

(2) The Company’s $1.2 billion USD and $500 million USD hybrid notes mature in 2076 and 2054, respectively, and these maturity dates have been used in the computation of the Company’s long-term debt principal and interest payment obligations at September 30, 2025.The Company has the option to repay such notes in advance of maturity upon exercise of the Company’s redemption

rights in accordance with the terms of the applicable indenture. Emera’s $1.2 billion USD hybrid notes are redeemable,

at Emera’s option, in June 2026.

(3) 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, 2025, including any expected required payment under associated swap agreements.

(4) Includes $324 million related to NMGC (2025: $7 million, 2026: $26 million, 2027: $22 million, 2028: $22 million, 2029: $22 million, and $225 million thereafter).

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

(6) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $124 million related to a gas transportation contract between PGS and SeaCoast through 2040.

(7) Includes $65 million related to NMGC (2025: $11 million, 2026: $23 million, 2027: $15 million, 2028: $12 million, and 2029: $4 million).

(8) Includes $186 million related to NMGC (2025: $53 million, 2026: $117 million, 2027: $13 million, and 2028: $3 million).

(9) Includes the estimated contractual obligation, which 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 November 2024, the NSEB approved the collection of up to $197 million from NSPI for the recovery of Maritime Link costs in 2025. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to NSEB approval.

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

Debt Management

In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to unsecured committed syndicated revolving and non-revolving bank lines of credit in either CAD or USD, per the table below as at September 30, 2025.

millions of dollars in currency as noted below		CreditFacilities		Utilized		UndrawnandAvailable
In CAD:
Emera – committed revolving credit facility	June 2029	$	1,300	$	1,083	$	217
NSPI – committed revolving credit facility	June 2029		800		377		423
NSPI – non-revolving<br>facility	May 2026		500		500		-
Emera – non-revolving<br>facility	February 2026		200		200		-
In :
TEC – committed revolving credit facility	December 2028		800		511		289
TECO Finance, Inc. – committed revolving credit<br>facility	December 2028		400		23		377
PGS – revolving facility	December 2028		250		144		106
NMGC – revolving credit facility	December 2027		125		83		42
Other – committed revolving credit facilities	Various		28		8		20

All values are in US Dollars.

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, 2025.

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

Florida Electric Utility

On March 6, 2025, TEC issued $600 million USD of senior unsecured notes that bear interest at 5.15 per cent with a maturity date of March 1, 2035. Proceeds from this issuance were used for the repayment of a portion of TEC’s outstanding commercial paper.

Canadian Electric Utilities

On May 21, 2025, NSPI entered into a $500 million non-revolving facility which matures on May 21, 2026. The credit agreement contains customary representations and warranties, events of default and financial and other covenants. The non-revolving facility’s interest rates are referenced to the Term CORRA or prime rate, plus a margin. Proceeds from this facility were used for general corporate purposes.

Gas Utilities and Infrastructure

On October 23, 2025, NMGC entered into a $70 million USD, 364-day term loan agreement which matures on October 22, 2026. The credit agreement contains customary representations and warranties, events of default and financial and other covenants. The non-revolving facility’s interest rates are referenced to the Term SOFR plus a margin. Proceeds from this facility were used for general corporate purposes.

On September 19, 2025, NMGC amended its $125 million USD unsecured committed revolving credit facility to extend the maturity date from December 17, 2026, to December 17, 2027. There were no other changes in commercial terms from the prior agreement.

Other

On September 25, 2025, EUSHI Finance, Emera US Holdings Inc. and Emera filed a shelf registration statement on Form F-10 and Form F-3 (“Registration Statement”), with the Nova Scotia Securities Commission (“NSSC”) and the SEC under the US/Canada Multijurisdictional Disclosure System. The Registration Statement was filed in connection with the prospective offer and issue by EUSHI Finance of one or more series of senior and/or subordinated unsecured debt securities (“Debt Securities”), in an aggregate principal amount of up to $3 billion USD, during the 25-month period that the short form base shelf prospectus contained in the Registration Statement (“Base Shelf Prospectus”), including any further amendments thereto, remains valid. The Debt Securities may be offered in one or more transactions, at prices, with maturities and on terms to be set forth in one or more prospectus supplements to be filed with the NSSC and the SEC at the time of any such offering.

On October 3, 2025, EUSHI Finance completed an issuance of $750 million USD fixed-to-fixed reset rate junior subordinated notes, pursuant to the prospectus supplement dated September 29, 2025, to the Base Shelf Prospectus. The notes initially bear interest at a rate of 6.25 per cent, and will reset on April 1, 2031, and every five years thereafter, to a rate per annum equal to the five-year US treasury rate plus 2.509 per cent, subject to an interest rate floor of 6.25 per cent. The notes mature on April 1, 2056. EUSHI Finance, 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, plus accrued and unpaid interest on the notes to be redeemed, in accordance with the terms of the prospectus supplement; and otherwise, at the times and the redemption prices described in the prospectus supplement. The notes are fully and unconditionally guaranteed, on a joint, several and subordinated basis, by Emera, and Emera US Holdings Inc. Proceeds from this issuance will be used for general corporate purposes, including repayment of existing debt.

On February 20, 2025, Emera amended its $200 million unsecured non-revolving facility to extend the maturity date from February 19, 2025 to February 19, 2026. There were no other material changes to the terms from the prior agreement.

CreditRatings

Emera’s credit ratings are consistent with those disclosed in the Company’s 2024 annual MD&A, with material updates noted below:

On May 27, 2025, Fitch Ratings revised its outlook on Emera, TEC and PGS to stable from negative with no changes to existing ratings.

Guarantees and Letters of Credit

Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2024

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

Emera, on behalf of Brunswick Pipeline, issued a standby letter of credit for $22 million to secure obligations under a non-revolving loan agreement. This standby letter of credit has a one-year term, expiring on March 31, 2026, and will be renewed annually, as required.

The Company has standby letters of credit and surety bonds in the amount of $136 million USD (December 31, 2024 – $105 million USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed annually, as required.

Emera, 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 2026. The amount committed as at September 30, 2025 was $70 million (December 31, 2024 – $58 million).

Outstanding Stock Data

Common Stock

	millions of		millions of
Issued and outstanding:	shares		dollars
Balance, December 31,<br>2024		295.94	$	9,042
Conversion of Convertible Debentures		0.02		1
Issuance of common stock under ATM program (1)		0.19		10
Issued under the DRIP, net of discounts		3.80		225
Senior management stock options exercised and Employee Share<br>Purchase Plan		0.65		34
Balance, September 30,2025	****	300.60	$	9,312

(1) For the three months ended September 30, 2025, no common shares were issued under Emera’s ATM program. For the nine months ended September 30, 2025, a total of 187,600 common shares were issued under Emera’s ATM program at an average price of $53.58 per share for gross proceeds of $10 million ($10 million, net of after-tax issuance costs). As at September 30, 2025, an aggregate gross sales limit of $326 million remained available for issuance under the ATM program, which expired on November 4, 2025.

As at November 5, 2025, the amount of issued and outstanding common shares was 300.7 million.

If all outstanding stock options were converted as at November 5, 2025, an additional 4.1 million common shares would be issued and outstanding.

Preferred Stock

As at November 5, 2025, Emera had the following preferred shares issued and outstanding: Series A – 6.0 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.

On July 9, 2025, Emera announced that it would not redeem the currently outstanding Cumulative 5-Year Rate Reset Preferred Shares, Series A (“Series A Shares”) or the Cumulative Floating Rate First Preferred Shares, Series B (“Series B Shares”) on August 15, 2025 (the “Conversion Date”).

On July 16, 2025, Emera announced a dividend rate of 4.951 per cent per annum on the Series A Shares during the five-year period commencing on August 15, 2025 and ending on (and inclusive of) August 14, 2030 ($0.3094 per Series A Share per quarter).

During the conversion period between July 16, 2025 and July 31, 2025, the holders of Series A Shares had the right, at their option, to convert all or any of their Series A Shares, on a one-for-one basis, into Series B Shares and the holders of Series B Shares had the right, at their option, to convert all or any of their Series B Shares, on a one-for-one basis, into Series A Shares. On August 7, 2025, Emera announced, after having taken into account all shares tendered for conversion by holders of its Series A Shares and Series B Shares, as the case may be (collectively, the “Holders”), by the end of the conversion period, the Company has determined that there would be outstanding on the Conversion Date less than 1 million Series B Shares. Therefore, in accordance with certain rights, privileges, restrictions and conditions attaching to the Series A Shares and the Series B Shares, the Company advised the Holders that no Series A Shares would be converted into Series B Shares and all remaining Series B Shares would automatically be converted into Series A Shares on a one-for-one basis on the Conversion Date. On the Conversion Date, there were 6 million Series A Shares and no Series B Shares outstanding.

On January 16, 2025, Emera announced that the annual fixed dividend per share for Series F shares would be reset from $1.0505 to $1.4372 for the five-year period from and including February 15, 2025.

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<br>Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $49 million for the three months ended September 30, 2025 (2024 – $41 million) and $140 million for the nine<br>months ended September 30, 2025 (2024 – $123 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,<br>refer to the “Contractual Obligations” section.
•	Natural gas transportation capacity purchases from M&NP are reported in the Condensed Consolidated Statements of<br>Income. Purchases from M&NP reported net in Operating revenues – non-regulated, totalled $1 million for the three months ended September 30, 2025 (2024 – $2 million) and<br>$12 million for the nine months ended September 30, 2025 (2024 – $8 million).
---	---
•	On March 5, 2025, NSPI sold development assets associated with the Wasoqonatl transmission line project to WTI for<br>consideration of $15 million. The development assets were sold at cost with no gain or loss recognized in the Condensed Consolidated Statements of Income.
---	---

As at September 30, 2025, Emera and its associated companies had $41 million due to related parties (December 31, 2024 – $24 million) recorded in “Other Current Liabilities” on the Condensed Consolidated Balance Sheets.

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 2024 annual MD&A. In April 2025, Emera and NSPI were impacted by a Cybersecurity Incident, as more particularly described in the “Other Developments” section. For more information on risks associated with cybersecurity generally, refer to the “Enterprise Risk and Risk Management” section of Emera’s 2024 annual MD&A.

Derivative Assets and Liabilities Recognized on the Balance Sheet

As at	September 30		December 31
millions of dollars	2025		2024
Regulatory Deferral:
Derivative instrument assets (1)	$	27	$	45
Derivative instrument liabilities (2)	****	(36)		(40)
Regulatory assets (1)	****	36		53
Regulatory liabilities (2)	****	(22)		(44)
Net asset	$	5	$	14
HFT Derivatives:
Derivative instrument assets (1)	$	206	$	122
Derivative instrument liabilities (2)	****	(505)		(542)
Net liability	$	(299)	$	(420)
Other Derivatives:
Derivative instrument assets (1)	$	41	$	-
Derivative instrument liabilities (2)	****	(6)		(36)
Net asset (liability)	$	35	$	(36)

(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	2025		2024		2025		2024
Regulatory Deferral:
Regulated fuel for generation and purchased power (1)	$	(6)	$	(15)	$	(12)	$	(36)
HFT Derivatives:
Non-regulated operating<br>revenues	$	16	$	59	$	480	$	209
Other Derivatives:
OM&G	$	11	$	22	$	36	$	8
Other income, net	****	(16)		5	****	21		(15)
Net gains (losses)	$	(5)	$	27	$	57	$	(7)
Total net gains	$	5	$	71	$	525	$	166

(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, 2025, the unrealized gain in accumulated other comprehensive income was $10 million, after-tax (December 31, 2024 – $12 million, after-tax). For the three and nine months ended September 30, 2025, unrealized gains of $1 million (September 30, 2024 – $1 million) and $2 (September 30, 2024 – $2 million), respectively, have been reclassified into interest expense.

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, designed the Company’s DC&P and ICFR as at September 30, 2025, 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.

Change in ICFR

In April 2025, the Company experienced a Cybersecurity Incident that impacted certain financial systems and processes at its Canadian affiliates. As a result, the Company transitioned these to business continuity processes and implemented additional ICFR during this period. This transition to business continuity processes resulted in a material change in the Company’s ICFR at Canadian affiliates during the quarter ended June 30, 2025. Since this time, the Company has restored certain financial systems and transitioned back from corresponding business continuity processes, which resulted in a material change in the Company’s ICFR at its Canadian affiliates during the quarter ended September 30, 2025. For more information on the Cybersecurity Incident, refer to the “Other Developments” section.

There were no other changes in the Company’s ICFR during the quarter ended September 30, 2025, 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 Q2 2025, the Company recognized a $75 million CAD ($55 million USD), pre-tax, non-cash impairment charge related to the pending sale of NMGC. For more information on the impairment charge, refer to note 3 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 2024 annual MD&A.

CHANGES IN ACCOUNTINGPOLICIES 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.

Targeted Improvements to the Accounting for Internal-Use Software

In September 2025, the FASB issued ASU 2025-06, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Targeted Improvements to the Accounting for Internal-Use Software. The standard update modernizes accounting for internal-use software by eliminating references to project stages and clarifying the threshold to begin capitalizing costs. The standard update also specifies that the disclosure requirements under ASC 360, Property, Plant and Equipment*,* apply to capitalized software costs accounted under ASC 350-40. The guidance will be effective for annual reporting periods beginning after December 15, 2027, and interim reporting periods within those annual reporting periods. Early adoption is permitted. The standard updates are to be applied using either a prospective, retrospective, or modified transition approach. The Company is currently evaluating the impact of adoption of the standard update on its consolidated financial statements.

Disaggregation of Income StatementExpenses

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 TaxDisclosures

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.

SUMMARY OF QUARTERLY RESULTS

For the quarter ended<br> <br>millions of dollars	****	Q3		Q2		Q1		Q4		Q3		Q2		Q1		Q4
(except per share amounts)	2025		2025		2025		2024		2024		2024		2024		2023
Operating revenues	$	2,106	$	1,988	$	2,676	$	1,763	$	1,802	$	1,617	$	2,018	$	1,972
Net income attributable to common shareholders	$	228	$	135	$	583	$	154	$	4	$	129	$	207	$	289
EPS – basic	$	0.76	$	0.45	$	1.96	$	0.52	$	0.01	$	0.45	$	0.73	$	1.04
EPS – diluted	$	0.76	$	0.45	$	1.96	$	0.52	$	0.01	$	0.45	$	0.73	$	1.04

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. Quarter-over-quarter variances are discussed further below.

Q3 2025 compared to Q3 2024

For explanation of variances, refer to the “Consolidated Income Statement Highlights” section.

Q2 2025 compared to Q2 2024

Q2 2025 net income attributable to common shareholders increased by $6 million primarily due to decreased MTM losses; increased earnings at TEC, EES, and NMGC; higher Corporate income tax recovery; and decreased Corporate OM&G. These were partially offset by the gain on sale of LIL recognized in Q2 2024; charges related to the pending sale of NMGC recognized in Q2 2025; lower earnings at NSPI; decreased equity earnings from LIL; and increased Corporate interest expense. Q2 2025 EPS – basic and diluted were consistent with Q2 2024.

Q1 2025 compared to Q1 2024

Q1 2025 net income attributable to common shareholders increased by $376 million and EPS – basic and diluted increased by $1.23 compared to Q1 2024. The increases were primarily due to decreased MTM losses; increased earnings at TEC, NSPI, EES and NMGC; the impact of a weaker CAD; and decreased Corporate OM&G. These changes were partially offset by decreased income from equity investments due to the sale of LIL. The change in EPS was also impacted by an increase in weighted average shares outstanding.

Q4 2024 compared to Q4 2023

Q4 2024 net income attributable to common shareholders decreased by $135 million and EPS – basic and diluted decreased by $0.52 compared to Q4 2023. The decreases were primarily due to decreased MTM gains; charges related to wind-down costs and certain asset impairments; lower equity earnings from LIL; increased Corporate OM&G due to the timing difference in the valuation of long-term incentive expenses and related hedges; decreased earnings at Emera Energy; and increased Corporate interest expense. These changes were partially offset by the tax benefit related to a specific financing structure and its wind-up; increased earnings at NSPI, Other Electric Utilities, NMGC, PGS, and TEC; valuation allowance reversal related to the gain on sale of LIL; and increased Corporate income tax recovery. The change in EPS was also impacted by an increase in weighted average shares outstanding.

EX-99.2

Exhibit 99.2

EMERA INCORPORATED

Unaudited CondensedConsolidated

Interim Financial Statements

September 30, 2025 and 2024

Emera Incorporated

Condensed Consolidated Statements of Income (Unaudited)

	Three months ended				Nine months ended
For the		September 30				September 30
millions of dollars (except per share amounts)	****	2025		2024	****	2025		2024
Operating revenues
Regulated electric	$	1,829	$	1,534	$	5,227	$	4,431
Regulated gas	****	308		291	****	1,264		1,134
Non-regulated	****	(31)		(23)	****	279		(128)
Total operating revenues (note 5)	****	2,106		1,802	****	6,770		5,437
Operating expenses
Regulated fuel for generation and purchased power	****	547		484	****	1,653		1,487
Regulated cost of natural gas	****	53		46	****	346		282
Operating, maintenance and general expenses<br>(“OM&G”)	****	578		432	****	1,673		1,415
Provincial, state and municipal taxes	****	124		110	****	364		325
Depreciation and amortization	****	324		293	****	959		866
Impairment charges (note 3)	****	-		221	****	75		221
Total operating expenses	****	1,626		1,586	****	5,070		4,596
Income from operations	****	480		216	****	1,700		841
Income from equity investments (note 7)	****	15		25	****	48		87
Other income, net (note 8)	****	19		14	****	135		232
Interest expense, net	****	260		241	****	764		725
Income before provision for income taxes	****	254		14	****	1,119		435
Income tax expense (recovery) (note 9)	****	6		(9)	****	116		40
Net income	****	248		23	****	1,003		395
Non-controlling interest in subsidiaries<br>(“NCI”)	****	1		1	****	1		1
Preferred stock dividends	****	19		18	****	56		54
Net income attributable to common shareholders	$	228	$	4	$	946	$	340
Weighted average shares of common stock outstanding<br><br><br>(in millions) (note 11)
Basic	****	299.9		290.0	****	298.5		287.5
Diluted	****	300.6		290.1	****	299.0		287.6
Earnings per common share (note 11)
Basic	$	0.76	$	0.01	$	3.17	$	1.18
Diluted	$	0.76	$	0.01	$	3.16	$	1.18
Dividends per common share declared	$	0.7250	$	0.7175	$	2.1750	$	2.1525

The accompanying notes are an integral part of these condensed consolidated interim financial statements.

Emera Incorporated

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

	Three months ended				Nine months ended
For the		September 30				September 30
millions of dollars	****	2025		2024	****	2025		2024
Net income	$	248	$	23	$	1,003	$	395
Other comprehensive income (loss) (“OCI”), net of tax
Foreign currency translation adjustment (1)	****	257		(165)	****	(428)		240
Unrealized (losses) gains on net investment hedges (2)	****	(33)		22	****	56		(33)
Cash flow hedges – net of reclassification adjustment for<br>gains included in income	****	(1)		(1)	****	(2)		(2)
Unrealized gains on available-for-sale investment	****	1		-	****	1		1
Net change in unrecognized pension and post-retirement benefit<br>obligation	****	1		-	****	(3)		1
OCI (1)	$	225	$	(144)	$	(376)	$	207
Comprehensive income (loss)	****	473		(121)	****	627		602
Comprehensive income attributable to NCI	****	1		1	****	1		1
Comprehensive income (loss) of Emera Incorporated	$	472	$	(122)	$	626	$	601

The accompanying notes are an integral part of these condensed consolidated interim financial statements.

(1) Net of tax expense of $3 million (2024 – $2 million recovery) for the three months ended September 30, 2025 and tax recovery of $6 million (2024 – $3 million expense) for the nine months ended September 30, 2025.

(2) The Company has designated $1.2 billion United States dollar (“USD”) denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in USD denominated operations.

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited)

As at	September 30		December 31
millions of dollars	2025		2024
Assets
Current assets
Cash and cash equivalents	212	$	196
Restricted cash	14		17
Inventory	850		781
Derivative instruments (notes 13 and 14)	221		115
Regulatory assets (note 6)	500		595
Receivables and other current assets (note 16)	2,105		1,811
Assets held for sale (note 3)	124		173
	4,026		3,688
Property, plant and equipment (“PP&E”), net<br>of accumulated depreciation and amortization of 10,793 and 10,442, respectively	27,000		26,168
Other assets
Deferred income taxes (note 9)	371		392
Derivative instruments (notes 13 and 14)	48		51
Regulatory assets (note 6)	2,732		2,832
Net investment in direct finance and sales type leases	583		610
Investments subject to significant influence (note 7)	637		654
Goodwill	5,667		5,858
Other long-term assets (note 23)	639		538
Assets held for sale (note 3)	2,100		2,160
	12,777	****	13,095
Total assets	43,803	$	42,951

All values are in US Dollars.

The accompanying notes are an integral part of these condensed consolidated interim financial statements.

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited) – Continued

As at	****	September 30		December 31
millions of dollars	****	2025		2024
Liabilities and Equity
Current liabilities
Short-term debt (note 18)	$	1,665	$	1,400
Current portion of long-term debt (note 19)	****	1,170		234
Accounts payable	****	1,813		1,992
Derivative instruments (notes 13 and 14)	****	473		526
Regulatory liabilities (note 6)	****	218		262
Other current liabilities	****	614		489
Liabilities associated with assets held for sale (note 3)	****	323		212
	****	6,276	****	5,115
Long-term liabilities
Long-term debt (note 19)	****	17,809		18,173
Deferred income taxes (note 9)	****	2,418		2,331
Derivative instruments (notes 13 and 14)	****	74		91
Regulatory liabilities (note 6)	****	1,483		1,618
Pension and post-retirement liabilities (note 17)	****	269		274
Other long-term liabilities (note 7)	****	953		910
Liabilities associated with assets held for sale (note 3)	****	1,037		1,148
	****	24,043	****	24,545
Equity
Common stock (note 10)	****	9,312		9,042
Cumulative preferred stock	****	1,422		1,422
Contributed surplus	****	85		84
Accumulated other comprehensive income (“AOCI’) (note<br>12)	****	885		1,261
Retained earnings	****	1,766		1,468
Total Emera Incorporated equity	****	13,470		13,277
Non-controlling interest in<br>subsidiaries (“NCI”)	****	14		14
Total equity	****	13,484		13,291
Total liabilities and equity	$	43,803	$	42,951
Commitments and contingencies (note 20)

The accompanying notes are an integral part of these condensed consolidated interim financial statements.

Approved on behalf of the Board of Directors

“KarenSheriff”*****************“Scott Balfour”*

Chair of the Board President and Chief Executive Officer

Emera Incorporated

Condensed Consolidated Statements of Cash Flows (Unaudited)

For the	Nine months ended September 30
millions of dollars	2025		2024
Operating activities
Net income	$	1,003	$	395
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	****	963		878
Income from equity investments, net of dividends	****	5		(10)
Allowance for funds used during construction (“AFUDC”) –<br>equity	****	(49)		(36)
Deferred income taxes, net	****	119		14
Net change in pension and post-retirement liabilities	****	(38)		(40)
Nova Scotia Power (“NSPI”) fuel adjustment mechanism<br>(“FAM”)	****	(123)		18
Net change in fair value (“FV”) of derivative instruments	****	(185)		50
Net change in regulatory assets and liabilities	****	225		231
Net change in capitalized transportation capacity	****	(44)		134
Impairment charges	****	75		210
Gain on sale of the Labrador Island Link Partnership (“LIL”), excluding<br>transaction costs	****	-		(191)
Other operating activities, net	****	21		79
Changes in non-cash working<br>capital (note 22)	****	(382)		220
Net cash provided by operating activities	****	1,590		1,952
Investing activities
Additions to PP&E	****	(2,566)		(2,223)
Proceeds on disposal of assets	****	47		6
Proceeds from disposal of investment subject to significant influence	****	-		927
Other investing activities	****	1		1
Net cash used in investing activities	****	(2,518)		(1,289)
Financing activities
Change in short-term debt, net	****	(347)		(83)
Proceeds from short-term debt with maturities greater than 90 days	****	500		-
Proceeds from long-term debt, net of issuance costs	****	919		1,359
Retirement of long-term debt	****	(176)		(1,082)
Net proceeds (repayments) under committed credit facilities	****	485		(941)
Issuance of common stock, net of issuance costs	****	40		200
Dividends on common stock	****	(423)		(399)
Dividends on preferred stock	****	(56)		(54)
Other financing activities	****	(1)		3
Net cash provided by (used in) financing activities	****	941		(997)
Effect of exchange rate changes on cash, cash equivalents, restricted cash and cash associated with assets held for sale	****	(5)		10
Net increase (decrease) in cash, cash equivalents, restricted cash, and cash associated with assets held for sale	****	8		(324)
Cash, cash equivalents, restricted cash and cash associated with assets held for sale, beginning of period	****	221		588
Cash, cash equivalents, restricted cash and cash associated with<br>assets held for sale, end of period	$	229	$	264
Cash, cash equivalents, restricted cash and cash associated with assets held for sale consists of:
Cash	$	207	$	235
Short-term investments	****	5		5
Restricted cash	****	14		20
Cash associated with assets held for sale	****	3		4
Total	$	229	$	264

The accompanying notes are an integral part of these condensed consolidated interim financial statements.

Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)

		Preferred		Contributed				Retained				Total
millions of dollars	Stock	****	Stock	****	Surplus	****	AOCI	****	Earnings	****	NCI	****	Equity
For the three months ended September 30,<br>2025
Balance, June 30, 2025	9,228	$	1,422	$	85	$	660	$	1,755	$	14	$	13,164
Net income of Emera Incorporated	-	****	-	****	-	****	-	****	247	****	1	****	248
OCI, net of tax expense of 3 million	-	****	-	****	-	****	225	****	-	****	-	****	225
Dividends declared on preferred stock (1)	-	****	-	****	-	****	-	****	(19)	****	-	****	(19)
Dividends declared on common stock (0.7250/share)	-	****	-	****	-	****	-	****	(217)	****	-	****	(217)
Issued under the Dividend Reinvestment Program (“DRIP”), net of discounts	72	****	-	****	-	****	-	****	-	****	-	****	72
Senior management stock options exercised and Employee Common Share Purchase Plan (“ECSPP”)	11	****	-	****	-	****	-	****	-	****	-	****	11
Other	1	****	-	****	-	****	-	****	-	****	(1)	****	-
Balance, September 30, 2025	9,312	$	1,422	$	85	$	885	$	1,766	$	14	$	13,484
For the nine months ended September 30,<br>2025
Balance, December 31, 2024	9,042	$	1,422	$	84	$	1,261	$	1,468	$	14	$	13,291
Net income of Emera Incorporated	-	****	-	****	-	****	-	****	1,002	****	1	****	1,003
OCI, net of tax recovery of 6 million	-	****	-	****	-	****	(376)	****	-	****	-	****	(376)
Dividends declared on preferred stock (2)	-	****	-	****	-	****	-	****	(56)	****	-	****	(56)
Dividends declared on common stock (2.1750/share)	-	****	-	****	-	****	-	****	(648)	****	-	****	(648)
Issued under the DRIP, net of discounts	225	****	-	****	-	****	-	****	-	****	-	****	225
Issuance of common stock under the at-the-market (“ATM”) program, net of after-tax issuance costs	10	****	-	****	-	****	-	****	-	****	-	****	10
Senior management stock options exercised and ECSPP	34	****	-	****	1	****	-	****	-	****	-	****	35
Other	1	****	-	****	-	****	-	****	-	****	(1)	****	-
Balance, September 30, 2025	9,312	$	1,422	$	85	$	885	$	1,766	$	14	$	13,484

All values are in US Dollars.

The accompanying notes are an integral part of these condensed consolidated interim financial statements.

(1) Series A; $0.1364/share, Series B; $0.2789/share, Series C; $0.4021/share, Series E; $0.2813/share, Series F; $0.3593/share; Series H; $0.3953/share; Series J; $0.2656/share and Series L; $0.2875/share

(2) Series A; $0.4092/share, Series B; $0.9451/share, Series C; $1.2064/share, Series E; $0.8438/share, Series F; $0.9813/share; Series H; $1.1858/share; Series J; $0.7969/share and Series L; $0.8625/share

Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)

		Preferred		Contributed				Retained				Total
millions of dollars	Stock	****	Stock	****	Surplus	****	AOCI	****	Earnings	****	NCI	****	Equity
For the three months ended September 30,<br>2024
Balance, June 30, 2024	8,657	$	1,422	$	83	$	656	$	1,729	$	14	$	12,561
Net income of Emera Incorporated	-		-		-		-		22		1		23
OCI, net of tax recovery of 2 million	-		-		-		(144)		-		-		(144)
Dividends declared on preferred stock (1)	-		-		-		-		(18)		-		(18)
Dividends declared on common stock (0.7175/share)	-		-		-		-		(207)		-		(207)
Issued under the DRIP, net of discounts	75		-		-		-		-		-		75
Issuance of common stock under the ATM program, net of after-tax issuance costs	146		-		-		-		-		-		146
Senior management stock options exercised and ECSPP	6		-		1		-		-		-		7
Other	-		-		-		-		-		(1)		(1)
Balance, September 30, 2024	8,884	$	1,422	$	84	$	512	$	1,526	$	14	$	12,442
For the nine months ended September 30,<br>2024
Balance, December 31, 2023	8,462	$	1,422	$	82	$	305	$	1,803	$	14	$	12,088
Net income of Emera Incorporated	-		-		-		-		394		1		395
OCI, net of tax expense of 3 million	-		-		-		207		-		-		207
Dividends declared on preferred stock (2)	-		-		-		-		(54)		-		(54)
Dividends declared on common stock (2.1525/share)	-		-		-		-		(617)		-		(617)
Issued under the DRIP, net of discount	217		-		-		-		-		-		217
Issuance under ATM program, net of after-tax issuance costs	181		-		-		-		-		-		181
Senior management stock options exercised and ECSPP	24		-		2		-		-		-		26
Other	-		-		-		-		-		(1)		(1)
Balance, September 30, 2024	8,884	$	1,422	$	84	$	512	$	1,526	$	14	$	12,442

All values are in US Dollars.

The accompanying notes are an integral part of these condensed consolidated interim financial statements.

(1) Series A; $0.1364/share, Series B; $0.4298/share, Series C; $0.4021/share, Series E; $0.2813/share, Series F; $0.2626/share; Series H; $0.3953/share; Series J; $0.2656/share and Series L; $0.2875/share

(2) Series A; $0.4092/share, Series B; $1.2948/share, Series C; $1.2064/share, Series E; $0.8438/share, Series F; $0.7879/share; Series H; $1.1858/share; Series J; $0.7969/share and Series L; $0.8625/share

Emera Incorporated

Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)

As at September 30, 2025 and 2024

1. SUMMARY OF SIGNIFICANTACCOUNTING POLICIES

Nature of Operations

Emera Incorporated (“Emera” or the “Company”) is an energy and services company that invests in electricity generation, transmission and distribution, and gas transmission and distribution.

At September 30, 2025, Emera’s reportable segments include the following:

•	Florida Electric Utility, which consists of Tampa Electric (“TEC”), a vertically integrated regulated electric<br>utility in West Central Florida.
•	Canadian Electric Utilities, which includes:
---	---
•	NSPI, a vertically integrated regulated electric utility and the primary electricity supplier in Nova Scotia;<br>
---	---
•	a 100 per cent equity interest in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link<br>Project, a $1.8 billion, including AFUDC, transmission project between the island of Newfoundland and Nova Scotia; and
---	---
•	A 50 per cent indirect voting equity interest in Wasoqonatl Transmission Incorporated (“WTI”), a<br>transmission line project to create a reliability intertie between Nova Scotia and New Brunswick. For more information, refer to note 7.
---	---
•	Gas Utilities and Infrastructure, which includes:
---	---
•	Peoples Gas System, Inc. (“PGS”), a regulated gas distribution utility operating across Florida;<br>
---	---
•	New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility serving customers in New Mexico. On<br>August 5, 2024, Emera announced an agreement to sell NMGC. The transaction is expected to close in early 2026, subject to certain approvals, including approval by the New Mexico Public Regulation Commission (“NMPRC”). For more<br>information on the pending transaction, refer to note 3;
---	---
•	Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a<br>145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick to the United States (“US”) border under a 25-year firm service agreement with Repsol Energy North America Canada Partnership (“Repsol Energy”), which expires in 2034;
---	---
•	SeaCoast Gas Transmission, LLC (“SeaCoast”), a regulated intrastate natural gas transmission company offering<br>services in Florida; and
---	---
•	a 12.9 per cent equity interest in Maritimes & Northeast Pipeline (“M&NP”), a 1,400-kilometre pipeline that transports natural gas throughout markets in Atlantic Canada and the northeastern US.
---	---
•	Other Electric Utilities, which includes Emera (Caribbean) Incorporated (“ECI”), a holding company with<br>regulated electric utilities that include:
---	---
•	The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated regulated electric<br>utility on the island of Barbados;
---	---
•	Grand Bahama Power Company Limited (“GBPC”), a vertically integrated regulated electric utility on Grand Bahama<br>Island; and
---	---
•	a 19.5 per cent equity interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically<br>integrated regulated electric utility on the island of St. Lucia.
---	---

•	Emera’s other segment includes investments in energy-related non-regulated<br>companies that are below the required threshold for reporting as separate segments and corporate expense and revenue items that are not directly allocated to the operations of Emera’s subsidiaries and investments. This includes:<br>
•	Emera Energy, which consists of:
---	---
•	Emera Energy Services (“EES”), a physical energy business that purchases and sells natural gas and electricity<br>and provides related energy asset management services;
---	---
•	Brooklyn Power Corporation (“Brooklyn Energy”), a 30 MW biomass<br>co-generation electricity facility in Brooklyn, Nova Scotia; and
---	---
•	a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a 660 MW pumped<br>storage hydroelectric facility in northwestern Massachusetts.
---	---
•	Emera US Finance LP, EUSHI Finance, Inc. (“EUSHI Finance”), and TECO Finance, Inc., financing subsidiaries of<br>Emera;
---	---
•	Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the US; and<br>
---	---
•	Other investments.
---	---

Basis of Presentation

These unaudited condensed consolidated interim financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”). The significant accounting policies applied to these unaudited condensed consolidated interim financial statements are consistent with those disclosed in the audited consolidated financial statements as at and for the year ended December 31, 2024.

In the opinion of management, these unaudited condensed consolidated interim financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 2025.

All dollar amounts are presented in Canadian dollars, unless otherwise indicated.

Use of Management 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 Q2 2025, the Company recognized a $75 million ($55 million USD), pre-tax, non-cash impairment charge related to the pending sale of NMGC. For more information on the impairment charge, refer to note 3. There were no other material changes in the nature of the Company’s critical accounting estimates from those disclosed in Emera’s 2024 annual audited consolidated financial statements.

Seasonal Nature of Operations

Interim results are not necessarily indicative of results for the full year, primarily due to seasonal factors. Electricity and gas sales, and related transmission and distribution, vary during the year. The first quarter provides strong earnings contributions from the Canadian Electric Utilities and Gas Utilities and Infrastructure segments, where winter is the peak electricity and gas usage season. The third quarter provides strong earnings contributions from the Florida Electric Utility segment due to summer being the heaviest electric consumption season. Certain quarters may also be impacted by weather and the number and severity of storms.

Cybersecurity Incident

On April 25, 2025, Emera and NSPI discovered a cybersecurity incident (the “Cybersecurity Incident”) involving unauthorized access into certain parts of its Canadian network and servers supporting portions of its business applications. Immediately following detection of the external threat, incident response and business continuity protocols were activated, including the engagement of leading third-party cybersecurity experts. Actions were taken to contain and isolate the affected servers and prevent further intrusion and to notify law enforcement in Canada and the US. There was no disruption to any of the Company’s Canadian physical operations, including at NSPI’s generation, transmission and distribution facilities, the Maritime Link, or the Brunswick Pipeline. There was no impact to Emera’s US or Caribbean utilities’ operations. The post-incident investigation is nearing completion.

2. FUTURE ACCOUNTING PRONOUNCEMENTS

Targeted Improvements to the Accounting for Internal-Use Software

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

3. DISPOSITIONS

Pending Sale of NMGC

As the transaction proceeds will be lower than the carrying amount of the assets and liabilities being sold,

in Q3 2024 Emera assessed the NMGC reporting unit for goodwill impairment by comparing the FV of expected transaction proceeds to the carrying value of net assets, including goodwill of $366 million USD. 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.

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.

In July 2025, the procedural schedule for the NMPRC regulatory process was revised with the public hearing rescheduled from June 2025 to November 2025. The transaction is expected to close in early 2026.

Details of the assets and liabilities classified as held for sale are as follows:

As at<br> <br>millions of dollars	September 30<br><br><br>2025		December 31<br><br><br>2024
Cash and cash equivalents	$	3	$	8
Inventory	****	9		9
Derivative instruments	****	5		1
Regulatory assets	****	32		28
Receivables and other current assets	****	75		127
Current assets held for sale	$	124	$	173
PP&E	****	1,865		1,845
Regulatory assets	****	8		6
Goodwill	****	292		303
Other long-term assets	****	26		23
Less: Adjustment to FV less costs to sell (1)	****	(91)		(17)
Long-term assets held for sale	$	2,100	$	2,160
Total assets held for sale	$	2,224	$	2,333
Short-term debt	$	114	$	46
Current portion of long-term debt	****	97		-
Derivative instruments	****	-		1
Regulatory liabilities	****	15		10
Accounts payable and other current liabilities	****	97		155
Current liabilities associated with assets held for sale	****	323		212
Long-term debt	****	576		696
Deferred income taxes	****	189		167
Regulatory liabilities	****	265		274
Other long-term liabilities	****	7		11
Long-term liabilities associated with assets held for sale	$	1,037	$	1,148
Total liabilities associated with assets held for sale	$	1,360	$	1,360

(1) Represents a $75 million impairment charge related to the remeasurement of the NMGC disposal group to FV (December 31, 2024 - nil) and $16 million in estimated transaction costs related to the pending sale (December 31, 2024 – $17 million).

Sale of LIL Equity Interest

On June 4, 2024, Emera completed the sale of its 31.1 per cent indirect minority equity interest in the LIL 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, 2025, the estimated FV of the escrow proceeds receivable is $25 million. In Q2 2024, a gain on sale, after transaction costs, of $182 million ($107 million, after tax and transaction costs), was recognized in “Other income, net” on the Condensed Consolidated Statements of Income and included in the Other segment.

4. SEGMENT INFORMATION

Emera manages its reportable segments separately due in part to their different operating, regulatory and geographical environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets, as reported to the Company’s chief operating decision maker (“CODM”). Emera’s CODM is the Chief Executive Officer.

millions of dollars	Florida<br>Electric<br>Utility		Canadian<br>Electric<br>Utilities			Gas Utilities<br>and<br>Infrastructure		Other<br>Electric<br>Utilities		Other			Inter-<br>Segment<br>Eliminations			Total
For the three months ended September 30, 2025
Operating revenues from external customers (1)	$	1,266	$	405		$	314	$	159	$	(38	)	$	-		$	2,106
Inter-segment revenues (1)		3		-			5		-		7			(15	)		-
Total operating revenues		1,269		405			319		159		(31	)		(15	)		2,106
Regulated fuel for generation and purchased power		281		189			-		83		-			(6	)		547
Regulated cost of natural gas		-		-			53		-		-			-			53
OM&G		315		98			113		36		25			(9	)		578
Provincial, state and municipal taxes		84		12			26		1		1			-			124
Depreciation and amortization		176		74			52		21		1			-			324
Income from equity investments		-		10			4		1		-			-			15
Other income, net		19		11			3		3		(17	)		-			19
Interest expense, net (2)		79		45			37		5		94			-			260
Income tax expense (recovery)		51		(5	)		13		-		(53	)		-			6
NCI		-		-			-		1		-			-			1
Preferred stock dividends		-		-			-		-		19			-			19
Net income (loss) attributable to common shareholders	$	302	$	13		$	32	$	16	$	(135	)	$	-		$	228
For the nine months ended September 30, 2025
Operating revenues from external customers (1)	$	3,353	$	1,440		$	1,282	$	435	$	260		$	-		$	6,770
Inter-segment revenues (1)		8		-			13		-		23			(44	)		-
Total operating revenues		3,361		1,440			1,295		435		283			(44	)		6,770
Regulated fuel for generation and purchased power		772		671			-		223		-			(13	)		1,653
Regulated cost of natural gas		-		-			346		-		-			-			346
OM&G		821		327			350		110		90			(25	)		1,673
Provincial, state and municipal taxes		237		37			86		3		1			-			364
Depreciation and amortization		523		221			152		58		5			-			959
Income from equity investments		-		32			14		3		(1	)		-			48
Other income, net		66		25			9		5		24			6			135
Interest expense, net (2)		226		129			112		15		282			-			764
Impairment charges		-		-			-		-		75			-			75
Income tax expense (recovery)		122		(39	)		72		3		(42	)		-			116
NCI		-		-			-		1		-			-			1
Preferred stock dividends		-		-			-		-		56			-			56
Net income (loss) attributable to common shareholders	$	726	$	151		$	200	$	30	$	(161	)	$	-		$	946
As at September 30, 2025
Total assets	$	24,747	$	8,131		$	8,477	$	1,439	$	1,882		$	(873	)	$	43,803
Investments subject to significant influence	$	-	$	470		$	112	$	55	$	-		$	-		$	637
Goodwill	$	4,871	$	-		$	796	$	-	$	-		$	-		$	5,667

(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E, OM&G, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are measured at the amount of consideration established by the related parties. Eliminated transactions are included in determining reportable segments.

(2) Segment net income is reported on a basis that includes internally allocated financing costs of $6 million for the three months ended September 30, 2025, and $20 million for the nine months ended September 30, 2025 between the Gas Utilities and Infrastructure and Other segments.

millions of dollars	Florida<br><br><br>Electric<br> <br>Utility		Canadian<br><br><br>Electric<br> <br>Utilities			Gas Utilities<br><br><br>and<br> <br>Infrastructure		Other<br><br><br>Electric<br> <br>Utilities		Other				Total
For the three months ended September 30, 2024
Operating revenues from external customers (1)	$	985	$	399		$	297	$	150	$	(29	)		$	1,802
Inter-segment revenues (1)		3		-			3		-		(8	)			-
Total operating revenues		988		399			300		150		(37	)			1,802
Regulated fuel for generation and purchased power		224		185			-		78		-		)		484
Regulated cost of natural gas		-		-			46		-		-				46
OM&G		196		87			103		39		12		)		432
Provincial, state and municipal taxes		73		12			24		1		-				110
Depreciation and amortization		156		71			46		18		2				293
Income from equity investments		-		12			4		1		8				25
Other income (expenses), net		15		7			5		2		(5	)	)		14
Interest expense, net (2)		66		41			38		5		91				241
Impairment charges		-		-			11		-		210				221
Income tax expense (recovery)		36		(4	)		11		-		(52	)			(9	)
NCI		-		-			-		1		-				1
Preferred stock dividends		-		-			-		-		18				18
Net income (loss) attributable to common shareholders	$	252	$	26		$	30	$	11	$	(315	)		$	4
For the nine months ended September 30, 2024
Operating revenues from external customers **** (1)	$	2,639	$	1,376		$	1,150	$	416	$	(144	)		$	5,437
Inter-segment revenues (1)		7		-			10		-		10		)		-
Total operating revenues		2,646		1,376			1,160		416		(134	)	)		5,437
Regulated fuel for generation and purchased power		641		639			-		217		-		)		1,487
Regulated cost of natural gas		-		-			282		-		-				282
OM&G		587		299			333		106		105		)		1,415
Provincial, state and municipal taxes		207		36			78		3		1				325
Depreciation and amortization		462		209			135		54		6				866
Income from equity investments		-		67			14		3		3				87
Other income, net		44		21			12		7		146				232
Interest expense, net (2)		197		126			115		16		271				725
Impairment charges		-		-			11		-		210				221
Income tax expense (recovery)		72		-			60		-		(92	)			40
NCI		-		-			-		1		-				1
Preferred stock dividends		-		-			-		-		54				54
Net income (loss) attributable to common shareholders	$	524	$	155		$	172	$	29	$	(540	)		$	340
As at December 31, 2024
Total assets	$	24,375	$	7,609		$	8,439	$	1,444	$	1,810		(726)	$	42,951
Investment subject to significant influence	$	-	$	475		$	124	$	55	$	-			$	654
Goodwill	$	5,035	$	-		$	823	$	-	$	-			$	5,858

All values are in US Dollars.

(2) Segment net income is reported on a basis that includes internally allocated financing costs of $8 million for the three months ended September 30, 2024, and $22 million for the nine months ended September 30, 2024 between the Gas Utilities and Infrastructure and Other segments.

5. REVENUE

The following disaggregates the Company’s revenue by major source:

	Electric						Gas		Other
millions of dollars	Florida<br><br><br>Electric<br> <br>Utility		Canadian<br><br><br>Electric<br> <br>Utilities		Other<br><br><br>Electric<br> <br>Utilities		Gas Utilities<br><br><br>and<br> <br>Infrastructure		Other		Inter-<br><br><br>Segment<br> <br>Eliminations		Total
For the three months ended September 30, 2025
Regulated Revenue
Residential	$	787	$	197	$	59	$	116	$	-	$	-	$	1,159
Commercial		323		122		81		103		-		-		629
Industrial		71		68		7		26		-		(6)		166
Other electric		117		10		2		-		-		-		129
Regulatory deferrals		(35)		-		7		-		-		-		(28)
Other (1)		6		8		3		52		-		(3)		66
Finance income (2)(3)		-		-		-		16		-		-		16
Regulated revenue		1,269		405		159		313		-		(9)		2,137
Non-Regulated Revenue
Marketing and trading margin (4)		-		-		-		-		(3)		-		(3)
Other non-regulated operating revenue		-		-		-		6		9		(8)		7
Mark-to-market (3)		-		-		-		-		(37)		2		(35)
Non-regulated revenue		-		-		-		6		(31)		(6)		(31)
Total operating revenues	$	1,269	$	405	$	159	$	319	$	(31)	$	(15)	$	2,106
For the nine months ended September 30, 2025
Regulated Revenue
Residential	$	1,909	$	788	$	152	$	568	$	-	$	-	$	3,417
Commercial		858		390		231		395		-		-		1,874
Industrial		205		203		21		76		-		(14)		491
Other electric		384		32		6		-		-		-		422
Regulatory deferrals		(13)		-		16		-		-		-		3
Other (1)		18		27		9		190		-		(8)		236
Finance income (2)(3)		-		-		-		48		-		-		48
Regulated revenue		3,361		1,440		435		1,277		-		(22)		6,491
Non-Regulated Revenue
Marketing and trading margin (4)		-		-		-		-		98		-		98
Other non-regulated operating revenue		-		-		-		18		25		(21)		22
Mark-to-market (3)		-		-		-		-		160		(1)		159
Non-regulated revenue		-		-		-		18		283		(22)		279
Total operating revenues	$	3,361	$	1,440	$	435	$	1,295	$	283	$	(44)	$	6,770

(1) Other includes rental revenues which do not represent revenue from contracts with customers.

(2) Revenue related to Brunswick Pipeline’s service agreement with Repsol Energy.

(3) Revenue which does not represent revenues from contracts with customers.

(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with customers.

	Electric						Gas		Other
millions of dollars	Florida<br>Electric<br>Utility		Canadian<br>Electric<br>Utilities		Other<br>Electric<br>Utilities		Gas Utilities<br>and<br>Infrastructure		Other		Inter-<br>Segment<br>Eliminations		Total
For the three months ended September 30, 2024
Regulated Revenue
Residential	$	643	$	191	$	56	$	107	$	-	$	-	$	997
Commercial		258		118		78		97		-		-		551
Industrial		56		70		9		24		-		(4)		155
Other electric		101		10		1		-		-		-		112
Regulatory deferrals		(76)		-		5		-		-		-		(71)
Other (1)		6		10		1		51		-		(3)		65
Finance income (2)(3)		-		-		-		16		-		-		16
Regulated revenue		988		399		150		295		-		(7)		1,825
Non-Regulated Revenue
Marketing and trading margin (4)		-		-		-		-		(7)		-		(7)
Other non-regulated<br>operating revenue		-		-		-		5		7		(5)		7
Mark-to-market (3)		-		-		-		-		(37)		14		(23)
Non-regulated<br>revenue		-		-		-		5		(37)		9		(23)
Total operating revenues	$	988	$	399	$	150	$	300	$	(37)	$	2	$	1,802
For the nine months ended September 30, 2024
Regulated Revenue
Residential	$	1,580	$	737	$	149	$	499	$	-	$	-	$	2,965
Commercial		710		371		224		361		-		-		1,666
Industrial		168		207		22		71		-		(11)		457
Other electric		318		31		4		-		-		-		353
Regulatory deferrals		(145)		-		13		-		-		-		(132)
Other (1)		15		30		4		167		-		(7)		209
Finance income (2)(3)		-		-		-		47		-		-		47
Regulated revenue		2,646		1,376		416		1,145		-		(18)		5,565
Non-Regulated Revenue
Marketing and trading margin (4)		-		-		-		-		42		-		42
Other non-regulated<br>operating revenue		-		-		-		15		22		(16)		21
Mark-to-market (3)		-		-		-		-		(198)		7		(191)
Non-regulated<br>revenue		-		-		-		15		(134)		(9)		(128)
Total operating revenues	$	2,646	$	1,376	$	416	$	1,160	$	(134)	$	(27)	$	5,437

(1) Other includes rental revenues which do not represent revenue from contracts with customers.

(2) Revenue related to Brunswick Pipeline’s service agreement with Repsol Energy.

(3) Revenue which does not represent revenues from contracts with customers.

(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with customers.

Remaining PerformanceObligations:

Remaining performance obligations primarily represent gas transportation contracts, lighting contracts, and long-term steam supply arrangements with fixed contract terms. As of September 30, 2025, the aggregate amount of the transaction price allocated to remaining performance obligations was $452 million (2024 – $453 million), including $14 million related to NMGC. This amount includes $124 million of future performance obligations related to a gas transportation contract between SeaCoast and PGS through 2040. This amount excludes contracts with an original expected length of one year or less and variable amounts for which Emera recognizes revenue at the amount to which it has the right to invoice for services performed. Emera expects to recognize revenue for the remaining performance obligations through 2045.

6. REGULATORY ASSETS AND LIABILITIES

A summary of regulatory assets and liabilities is provided below. For a detailed description regarding the nature of the Company’s regulatory assets and liabilities, refer to note 7 in Emera’s 2024 annual audited consolidated financial statements. Updates to regulatory environments are included below.

As at<br> <br>millions of dollars	September 302025		December 31<br>2024
Regulatory assets (1)
Deferred income tax regulatory assets	$	1,287	$	1,227
TEC capital cost recovery for early retired assets	****	732		737
Pension and post-retirement medical plan	****	376		395
Storm cost recovery clauses	****	322		613
TEC capital cost recovery for retired Polk Unit 1<br>components	****	185		205
NSPI FAM	****	67		-
Cost recovery clauses	****	57		33
Deferrals related to derivative instruments	****	36		42
Environmental remediations	****	27		29
Stranded cost recovery	****	26		27
Other (2)	****	117		119
	$	3,232	$	3,427
Current	$	500	$	595
Long-term	****	2,732		2,832
Total regulatory assets	$	3,232	$	3,427
Regulatory liabilities (1)
Deferred income tax regulatory liabilities	$	775	$	828
Accumulated reserve – cost of removal	****	722		733
Cost recovery clauses	****	84		121
BLPC Self-insurance fund (“SIF”) (note 23)	****	31		32
Deferrals related to derivative instruments	****	22		44
NSPI FAM	****	-		56
Other (2)	****	67		66
	$	1,701	$	1,880
Current	$	218	$	262
Long-term	****	1,483		1,618
Total regulatory liabilities	$	1,701	$	1,880

(1) On August 5, 2024, Emera announced an agreement to sell NMGC. As a result, NMGC’s assets and liabilities were classified as held for sale beginning in Q3 2024 and excluded from the table above. For further details on the pending transaction, refer to note 3.

(2) Comprised of regulatory assets and liabilities that are not individually significant.

Florida Electric Utility

Base Rates:

On September 4, 2025, TEC petitioned the Florida Public Service Commission (“FPSC”) to increase base revenue by $88 million USD to reflect the 2026 adjustment in accordance with its 2024 rate case decision. On November 4, 2025, the FPSC approved the adjustment, with new rates becoming effective January 1, 2026.

On February 3, 2025, the FPSC issued the final order approving the rate case decision, effective January 1, 2025. In February 2025, a motion for reconsideration on certain aspects of the final order was filed by an intervening party with the FPSC. On May 6, 2025, the FPSC denied the motion for reconsideration, except with respect to immaterial calculation corrections, and the final order was issued on June 11, 2025. In March 2025, two intervening parties each filed a notice of appeal to the Florida Supreme Court regarding the outcome of TEC’s 2024 base rate proceeding. To date, the intervening parties have not filed their briefs related to the appeal.

Storm Reserve:

Canadian Electric Utilities

NSPI

Base Rates:

On September 18, 2025, NSPI filed a consensus General Rate Application (“GRA”) with the Nova Scotia Energy Board (“NSEB”), formerly the Nova Scotia Utility and Review Board, reflecting a settlement agreement reached with customer representatives. The settlement reflects more than six months of discussion, consultation, and information sharing. The GRA proposes average annual rate increases of 1.8 per cent in 2026 and 2.4 per cent in 2027. The proposed rates would result in annual revenue (fuel and non-fuel) increases of $62 million in 2026 and $108 million in 2027. The hearing for the matter is scheduled for January 2026.

NSPML

On July 18, 2025, NSPML submitted an application to the NSEB requesting recovery of approximately $199 million in Maritime Link costs for 2026.

On November 29, 2024, NSPML received approval from the NSEB, to collect up to $197 million in 2025 from NSPI. Payments from NSPI are subject to a holdback of up to $4 million per month. There was no holdback recorded in 2025 year-to-date.

Gas Utilities and Infrastructure

PGS

Base Rates:

7. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME

	September 30		Carrying Value<br><br><br>as at<br> <br>December 31		Equity Income for the<br><br><br>three months ended<br> <br>September 30				Equity Income (loss)<br><br><br>for the<br> <br>nine months ended<br><br><br>September 30
millions of dollars	****	2025		2024	****	2025		2024	****	2025		2024	2025
NSPML	$	470	$	475	$	10	$	12	$	32	$	38	100.0
M&NP (1)	****	112		124	****	4		4	****	14		14	12.9
Lucelec (1)	****	55		55	****	1		1	****	3		3	19.5
LIL (2)	****	-		-	****	-		-	****	-		29	-
Bear Swamp (3)	****	-		-	****	-		8	****	(1)		3	50.0
WTI (4)	****	-		-	****	-		-	****	-		-	50.0
	$	637	$	654	$	15	$	25	$	48	$	87

(1) Emera has significant influence over the operating and financial decisions of these companies through Board representation and therefore, records its investment in these entities using the equity method.

(2) On June 4, 2024, Emera completed the sale of its equity interest in the LIL. For further details, refer to note 3.

(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $179 million distribution received in 2015. Bear Swamp’s credit investment balance of $90 million (December 31, 2024 – $92 million) is recorded in Other long-term liabilities on the Condensed Consolidated Balance Sheets.

(4) On March 5, 2025, NSPI, the Canada Infrastructure Bank (“CIB”) and the Wskijinu’k Mtmo’taqnuow Agency (“WMA”) announced the Wasoqonatl transmission line project to create a reliability intertie between Nova Scotia and New Brunswick. The project will be owned by a new regulated utility, WTI, which is wholly-owned by a newly formed limited partnership between NSPI, CIB and WMA. NSPI will be responsible for providing construction, operation, maintenance and administrative services to WTI. NSPI has a 50 per cent indirect voting interest in WTI. As of September 30, 2025, NSPI’s investment was nominal.

Emera accounts for its variable interest investment in NSPML as an equity investment (note 23). NSPML’s consolidated summarized balance sheet is as follows:

As at<br> <br>millions of<br>dollars	September 30<br><br><br>2025		December 31<br><br><br>2024
Current assets	$	69	$	37
PP&E	****	1,386		1,425
Regulatory assets	****	785		778
Non-current assets	****	27		27
Total assets	$	2,267	$	2,267
Current liabilities	$	91	$	55
Long-term debt (1)	****	1,524		1,570
Non-current<br>liabilities	****	182		167
Equity	****	470		475
Total liabilities and equity	$	2,267	$	2,267

(1) The project debt has been guaranteed by the Government of Canada. ****

8. OTHER INCOME, NET

	Three months ended				Nine months ended
For the	September 30				September 30
millions of dollars	2025		2024		2025		2024
AFUDC - equity	$	12	$	15	$	49	$	36
Interest income	****	8		4	****	28		13
Pension non-service cost<br>recovery	****	7		8	****	21		26
FX (losses) gains	****	(17)		6	****	23		(16)
Transaction costs related to the pending sale of NMGC (1)	****	-		(24)	****	(2)		(24)
Gain on sale of LIL, after transaction costs (1)	****	-		-	****	-		182
Other	****	9		5	****	16		15
	$	19	$	14	$	135	$	232

(1) For more information related to the gain on sale, after transaction costs, of Emera’s indirect minority equity interest in the LIL and the pending sale of NMGC, refer to note 3.

9. INCOME TAXES

The income tax provision differs from that computed using the enacted combined Canadian federal and provincial statutory income tax rate for the following reasons:

	Three months ended				Nine months ended
For the	September 30				September 30
millions of dollars	2025		2024		2025		2024
Income before provision for income taxes	$	254	$	14	$	1,119	$	435
Statutory income tax rate	****	29%		29%	****	29%		29%
Income taxes, at statutory income tax rate	****	74		4	****	325		126
Tax credits	****	(28)		(22)	****	(93)		(47)
Amortization of deferred income tax regulatory liabilities	****	(14)		(14)	****	(35)		(30)
Foreign tax rate variance	****	(14)		(11)	****	(35)		(26)
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities	****	(3)		(8)	****	(34)		(38)
Impairment charges	****	-		48	****	18		48
Valuation allowance	****	(5)		-	****	(15)		-
Tax effect of equity earnings	****	(2)		(4)	****	(10)		(12)
Additional impact from the sale of LIL equity interest	****	-		-	****	-		22
Other	****	(2)		(2)	****	(5)		(3)
Income tax expense (recovery)	$	6	$	(9)	$	116	$	40
Effective income tax<br>rate	****	2%		(64%)	****	10%		9%

US One Big Beautiful Bill Act (“OBBBA”):

On July 4, 2025, the OBBBA was signed into law. The OBBBA makes permanent many of the expired and expiring tax provisions originally enacted in the Tax Cuts and Jobs Act of 2017. It also includes significant changes in future years to the timing and availability of several clean energy tax credits previously enacted in the Inflation Reduction Act, including the investment tax credit and production tax credit. On August 15, 2025, the Internal Revenue Service released guidance on determining when projects have begun construction for purposes of qualifying for these tax credits. Emera is currently evaluating the impact of the enacted changes. To date in 2025, the OBBBA has not had an impact on the Company.

10. COMMON STOCK

Authorized: Unlimited number of non-par value common shares.

Issued and outstanding:	millions of shares		millions of dollars
Balance, December 31, 2024		295.94	$	9,042
Conversion of Convertible Debentures		0.02		1
Issuance of common stock under ATM program (1)		0.19		10
Issued under the DRIP, net of discounts		3.80		225
Senior management stock options exercised and ECSPP		0.65		34
Balance, September 30, 2025	****	300.60	$	9,312

(1) For the three months ended September 30, 2025, no common shares were issued under Emera’s ATM program. For the nine months ended September 30, 2025, a total of 187,600 common shares were issued under Emera’s ATM program at an average price of $53.58 per share for gross proceeds of $10 million ($10 million net of after-tax issuance costs). As at September 30, 2025, an aggregate gross sales limit of $326 million remained available for issuance under the ATM program, which expired on November 4, 2025.

11. EARNINGS PER SHARE

The following table reconciles the computation of basic and diluted earnings per share:

	Three months ended				Nine months ended
For the	September 30				September 30
millions of dollars (except per share amounts)	2025		2024		2025		2024
Numerator
Net income attributable to common shareholders	$	227.5	$	3.7	$	945.9	$	339.9
Diluted numerator	****	227.5		3.7	****	945.9		339.9
Denominator
Weighted average shares of common stock outstanding –<br>basic	****	299.9		290.0	****	298.5		287.5
Stock-based compensation	****	0.7		0.1	****	0.5		0.1
Weighted average shares of common stock outstanding –diluted	****	300.6		290.1	****	299.0		287.6
Earnings per common share
Basic	$	0.76	$	0.01	$	3.17	$	1.18
Diluted	$	0.76	$	0.01	$	3.16	$	1.18

12. ACCUMULATED OTHER COMPREHENSIVE INCOME

The components of AOCI, net of tax, are as follows:

millions of dollars	Unrealized<br>(loss) gain on<br>translation of<br>self-sustaining<br>foreign<br>operations		Net change in<br>net<br>investment<br>hedges		Gains<br>(losses) on<br>derivatives<br>recognized<br>as cash<br>flow hedges		Net change<br><br><br>in available-<br> <br>for-sale<br>investments		Net change in<br>unrecognized<br>pension and<br>post-<br>retirement<br>benefit costs		Total<br><br><br>AOCI
For the nine months ended September 30,<br>2025
Balance, January 1, 2025	$	1,396	$	(163)	$	12	$	-	$	16	$	1,261
OCI before reclassifications	****	(428)	****	56	****	-	****	1	****	-	****	(371)
Amounts reclassified from AOCI	****	-	****	-	****	(2)	****	-	****	(3)	****	(5)
Net current period OCI	****	(428)	****	56	****	(2)	****	1	****	(3)	****	(376)
Balance, September 30, 2025	$	968	$	(107)	$	10	$	1	$	13	$	885
For the nine months ended September 30,<br>2024
Balance, January 1, 2024	$	369	$	(24)	$	14	$	(2)	$	(52)	$	305
OCI before reclassifications		240		(33)		-		1		-		208
Amounts reclassified from AOCI		-		-		(2)		-		1		(1)
Net current period OCI		240		(33)		(2)		1		1		207
Balance, September 30, 2024	$	609	$	(57)	$	12	$	(1)	$	(51)	$	512

The reclassifications out of AOCI are as follows:

		Three months ended				Nine months ended
For the		September 30				September 30
millions of dollars		2025		2024		2025		2024
Affected line item in the Condensed<br><br><br>Consolidated Interim Financial Statements			Amounts reclassified from AOCI
Gain on derivatives recognized as cash flow hedges
Interest rate hedge	Interest expense, net	$	(1)	$	(1)	$	(2)	$	(2)
Net change in unrecognized pension and post-retirement benefit costs
Amounts reclassified into obligations	Pension and post-retirement benefits	****	1		-	****	(3)		1
Total reclassifications out of AOCI, for theperiod		$	-	$	(1)	$	(5)	$	(1)

13. DERIVATIVE INSTRUMENTS

The Company enters into futures, forwards, swaps and option contracts as part of its risk management strategy to limit exposure to:

●	commodity price fluctuations related to the purchase and sale of commodities in the course of normal operations;<br>
●	foreign exchange (“FX”) fluctuations on foreign currency denominated purchases and sales;<br>
---	---
●	interest rate fluctuations on debt securities; and
---	---
●	share price fluctuations on stock-based compensation.
---	---

The Company also enters into physical contracts for energy commodities. Collectively, these contracts are considered “derivatives”. The Company accounts for derivatives under one of the following four approaches:

Physical contracts that meet the normal purchases normal sales (“NPNS”) exemption are not recognized on the balance sheet; they are recognized in income when they settle. A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty credit worthy. The Company continually assesses contracts designated under the NPNS exemption and will discontinue treatment of these contracts under this exception if the criteria are no longer met.

Derivatives that qualify for hedge accounting are recorded at FV on the balance sheet. Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively hedge the identified cash flow risk both at the inception and over the term of the derivative. Specifically, for cash flow hedges, the change in the FV of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized.

---

Where documentation or effectiveness requirements are not met, the derivatives are recognized at FV with any changes in FV recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.

Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. These derivatives are recorded at FV on the balance sheet as derivative assets or liabilities. The change in FV of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes that any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates. Based on current direction from the FPSC, TEC and PGS have no derivatives related to hedging.

Derivatives that do not meet any of the above criteria are designated as held-for-trading (“HFT”) derivatives and are recorded on the balance sheet at FV, with changes normally recorded in net income of the period, unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply.

---

Derivative assets and liabilities relating to the foregoing categories consisted of the following:

	Derivative Assets				Derivative Liabilities
As at	September 30		December 31		September 30		December 31
millions of dollars	2025		2024		2025		2024
Regulatory deferral:
Commodity swaps and forwards	$	21	$	25	$	37	$	44
FX forwards	****	7		27	****	-		3
	****	28		52	****	37		47
HFT derivatives:
Power swaps and physical contracts	****	41		34	****	39		30
Natural gas swaps, futures, forwards, physical contracts	****	292		236	****	593		660
	****	333		270	****	632		690
Other derivatives:
Equity derivatives	****	36		-	****	-		2
FX forwards	****	5		-	****	6		34
	****	41		-	****	6		36
Total gross derivatives	****	402		322	****	675		773
Impact of master netting agreements:
Regulatory deferral	****	(1)		(7)	****	(1)		(7)
HFT derivatives	****	(127)		(148)	****	(127)		(148)
Total impact of master netting agreements	****	(128)		(155)	****	(128)		(155)
Less: Derivatives classified as held for sale (1)	****	(5)		(1)	****	-		(1)
Total derivatives	$	269	$	166	$	547	$	617
Current (2)	****	221		115	****	473		526
Long-term (2)	****	48		51	****	74		91
Total derivatives	$	269	$	166	$	547	$	617

(1) On August 5, 2024, Emera announced an agreement to sell NMGC. As a result, NMGC’s assets and liabilities were classified as held for sale beginning in Q3 2024. For further details on the pending transaction, refer to note 3.

(2) Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.

Cash Flow Hedges

On May 26, 2021, a treasury lock was settled for a gain of $19 million that is being amortized through interest expense over 10 years as the underlying hedged item settles. As of September 30, 2025, the unrealized gain in AOCI was $10 million, after-tax (December 31, 2024 – $12 million, after-tax). For the three and nine months ended September 30, 2025, unrealized gains of $1 million (2024 - $1 million) and $2 million (2024 - $2 million) respectively were reclassified from AOCI into interest expense, net. The Company expects $2 million of unrealized gains currently in AOCI to be reclassified into net income within the next twelve months.

Regulatory Deferral

The Company has recorded the following changes with respect to derivatives receiving regulatory deferral:

millions of dollars	Commodity<br><br><br>swaps and<br> <br>forwards		FX<br><br><br>forwards		Commodity<br><br><br>swaps and<br> <br>forwards		FX<br><br><br>forwards
For the three months ended September 30			****	2025				2024
Unrealized (loss) gain in regulatory assets	$	(17)	$	4	$	(14)	$	(1)
Unrealized (loss) gain in regulatory liabilities	****	(7)	****	6		(6)		(1)
Realized gain in regulatory assets	****	(2)	****	-		(3)		-
Realized loss in regulatory liabilities	****	2	****	-		1		-
Realized loss (gain) loss in inventory (1)	****	3	****	(1)		3		(1)
Realized loss (gain) in regulated fuel for generation and purchased power (2)	****	7	****	(1)		16		(1)
Total change in derivative instruments	$	(14)	$	8	$	(3)	$	(4)
For the nine months ended September 30			****	2025				2024
Unrealized (loss) gain in regulatory assets	$	(32)	$	3	$	(1)	$	-
Unrealized gain (loss) in regulatory liabilities	****	10	****	(12)		6		13
Realized gain in regulatory assets	****	(5)	****	-		(7)		-
Realized loss in regulatory liabilities	****	5	****	-		1		-
Realized loss (gain) in inventory (1)	****	10	****	(5)		10		(5)
Realized loss (gain) in regulated fuel for generation and purchased<br>power (2)	****	15	****	(3)		41		(5)
Total change in derivative instruments	$	3	$	(17)	$	50	$	3

(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.

(2) Realized (gains) losses on derivative instruments settled and consumed in the period and hedging relationships that have been terminated or the hedged transaction is no longer probable.

As at September 30, 2025, the Company had the following notional volumes designated for regulatory deferral that are expected to settle as outlined below:

millions		2026-2027
Commodity swaps and forwards purchases:
Natural gas (MMBtu)	2		19
Power (MWh)	-		1
FX forwards:
FX contracts (millions of )	67	$	203
Weighted average rate	1.3422		1.3546
% of requirements	80%		40%

All values are in US Dollars.

HFT Derivatives

The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives:

	Three months ended				Nine months ended
For the	September 30				September 30
millions of dollars	2025		2024		2025		2024
Power swaps and physical contracts in non-regulated operating revenues	$	3	$	-	$	3	$	11
Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues	****	13		59	****	477		198
Total gains in net income	$	16	$	59	$	480	$	209

As at September 30, 2025, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:

millions
Natural gas purchases (MMBtu)	156	391	137	56	74
Natural gas sales (MMBtu)	179	385	89	16	9
Power purchases (MWh)	1	1	-	-	-
Power sales (MWh)	1	1	1	-	-

Other Derivatives

As at September 30, 2025, the Company had equity derivatives in place to manage cash flow risk associated with forecasted future cash settlements of deferred compensation obligations and FX forwards in place to manage cash flow risk associated with forecasted USD cash inflows. The equity derivatives hedge the return on 2.9 million shares and extends until December 2025. The FX forwards have a combined notional amount of $403 million USD and expire in 2025 through 2026.

The Company has recognized the following realized and unrealized gains (losses) with respect to other derivatives:

millions of dollars	FX<br><br><br>forwards		Equity<br><br><br>derivatives		FX<br><br><br>forwards		Equity<br><br><br>derivatives
For the three months ended September 30			2025				2024
Unrealized gain in OM&G	$	-	$	11	$	-	$	22
Unrealized (loss) gain in other income, net	****	(14)	****	-		8		-
Realized loss in other income, net	****	(2)	****	-		(3)		-
Total (losses) gains in net income	$	(16)	$	11	$	5	$	22
For the nine months ended September 30			****	2025				2024
Unrealized gain in OM&G	$	-	$	36	$	-	$	8
Unrealized gain (loss) in other income, net	****	33	****	-		(8)		-
Realized loss in other income, net	****	(12)	****	-		(7)		-
Total gains (losses) in net income	$	21	$	36	$	(15)	$	8

Credit Risk

The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits, and derivative assets. Credit risk is the potential loss from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral are requested on any high-risk accounts.

The Company assesses the potential for credit losses on a regular basis and, where appropriate, maintains provisions. With respect to counterparties, the Company has implemented procedures to monitor the creditworthiness and credit exposure of counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in default probability rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the Company’s current default probability. Net asset positions are adjusted based on the counterparty’s current default probability. The Company internally assesses credit risk for counterparties that are not rated.

It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, FX and interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit to the Company for the value in excess of the credit limit where contractually required. The Company also obtains cash deposits from electric customers. The Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer required by the Company.

The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk to these counterparties. The Company generally enters into International Swaps and Derivatives Association agreements, North American Energy Standards Board agreements and/or Edison Electric Institute agreements. The Company believes entering into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance and default.

As at September 30, 2025, the Company had $178 million (December 31, 2024 – $140 million) in financial assets considered to be past due, which had been outstanding for an average 64 days. The FV of these financial assets was $165 million (December 31, 2024 – $128 million), the difference of which is included in the allowance for credit losses. These assets primarily relate to accounts receivable from electric and gas revenue.

Cash Collateral

The Company’s cash collateral positions consisted of the following:

As at<br> <br>millions of<br>dollars	September 30<br><br><br>2025		December 31<br><br><br>2024
Cash collateral provided to others	$	141	$	198
Cash collateral received from others	$	8	$	5

Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured credit rating as determined by certain major credit rating agencies. Certain derivatives contain financial assurance provisions that require collateral to be posted if a material adverse credit-related event occurs. If a material adverse event resulted in the senior unsecured debt falling below investment grade, the counterparties to such derivatives could request ongoing full collateralization.

As at September 30, 2025, the total FV of derivatives in a liability position was $547 million (December 31, 2024 – $617 million). If the credit ratings of the Company were reduced below investment grade, the full value of the net liability position could be required to be posted as collateral for these derivatives.

14. FV MEASUREMENTS

The Company is required to determine the FV of all derivatives except those which qualify for the NPNS exemption (see note 13) and uses a market approach to do so. The three levels of the FV hierarchy are defined as follows:

Level 1 – Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets (“quoted prices”) for identical assets and liabilities.

Level 2 – Where quoted prices for identical assets and liabilities are not available, the valuation of certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing houses.

Level 3 – Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally developed inputs. The primary reasons for a Level 3 classification are as follows:

•	While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping<br>and locational basis differentials.
•	The term of certain transactions extends beyond the period when quoted prices are available, and accordingly, assumptions<br>were made to extrapolate prices from the last quoted period through the end of the transaction term.
---	---
•	The valuations of certain transactions were based on internal models, although quoted prices were utilized in the<br>valuations.
---	---

Derivative assets and liabilities are classified in their entirety, based on the lowest level of input that is significant to the FV measurement.

The following tables set out the classification of the methodology used by the Company to FV its derivatives:

As at	September 30, 2025
millions of dollars	Level 1		Level 2		Level 3		Total
Assets
Regulatory deferral:
Commodity swaps and forwards	$	15	$	5	$	-	$	20
FX forwards	****	-	****	7	****	-	****	7
	****	15	****	12	****	-	****	27
HFT derivatives:
Power swaps and physical contracts	****	-	****	27	****	5	****	32
Natural gas swaps, futures, forwards, physical contracts and related<br>transportation	****	3	****	133	****	38	****	174
	****	3	****	160	****	43	****	206
Other derivatives:
FX forwards	****	-	****	5	****	-	****	5
Equity derivatives	****	36	****	-	****	-	****	36
	****	36	****	5	****	-	****	41
Less: Derivatives classified as held for sale (1)	****	-	****	(5)	****	-	****	(5)
Total assets	****	54	****	172	****	43	****	269
Liabilities
Regulatory deferral:
Commodity swaps and forwards	****	15	****	21	****	-	****	36
	****	15	****	21	****	-	****	36
HFT derivatives:
Power swaps and physical contracts	****	(2)	****	27	****	4	****	29
Natural gas swaps, futures, forwards and physical contracts	****	(8)	****	110	****	374	****	476
	****	(10)	****	137	****	378	****	505
Other derivatives:
FX forwards	****	-	****	6	****	-	****	6
	****	-	****	6	****	-	****	6
Total liabilities	****	5	****	164	****	378	****	547
Net assets (liabilities)	$	49	$	8	$	(335)	$	(278)

As at	December 31, 2024
millions of dollars	Level 1		Level 2		Level 3		Total
Assets
Regulatory deferral:
Commodity swaps and forwards	$	15	$	3	$	-	$	18
FX forwards		-		27		-		27
		15		30		-		45
HFT derivatives:
Power swaps and physical contracts		2		23		5		30
Natural gas swaps, futures, forwards, physical contracts and related<br>transportation		13		52		27		92
		15		75		32		122
Less: Derivatives classified as held for sale (1)		-		(1)		-		(1)
Total assets		30		104		32		166
Liabilities
Regulatory deferral:
Commodity swaps and forwards		18		19		-		37
FX forwards		-		3		-		3
		18		22		-		40
HFT derivatives:
Power swaps and physical contracts		2		21		4		27
Natural gas swaps, futures, forwards and physical contracts		(11)		89		437		515
		(9)		110		441		542
Other derivatives:
FX forwards		-		34		-		34
Equity derivatives		2		-		-		2
		2		34		-		36
Less: Derivatives classified as held for sale (1)		-		(1)		-		(1)
Total liabilities		11		165		441		617
Net assets (liabilities)	$	19	$	(61)	$	(409)	$	(451)

(1) On August 4, 2024, Emera announced an agreement to sell NMGC. As a result, NMGC’s assets and liabilities were classified as held for sale beginning in Q3 2024. For further details on the pending transaction, refer to note 3.

The change in the FV of the Level 3 financial assets and liabilities was as follows:

	Three months ended						Nine months ended
	September 30, 2025						September 30, 2025
	HFT Derivatives						HFT Derivatives
millions of dollars	Power		Natural<br>gas		Total		Power		Natural<br>gas		Total
Assets
Balance, beginning of period	$	5	$	27	$	32	$	5	$	27	$	32
Total realized and unrealized gains or losses included in non-regulated operating revenues		-		11	****	11		-		11	****	11
Balance, September 30, 2025	$	5	$	38	$	43	$	5	$	38	$	43
Liabilities
Balance, beginning of period	$	5	$	293	$	298	$	4	$	437	$	441
Total realized and unrealized gains or losses included in non-regulated operating revenues		(1)		81	****	80		-		(63)	****	(63)
Balance, September 30, 2025	$	4	$	374	$	378	$	4	$	374	$	378

Significant unobservable inputs used in the FV measurement of Emera’s natural gas and power derivatives include third-party sourced pricing for instruments based on illiquid markets. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) FV measurement. Other unobservable inputs used include internally developed correlation factors and basis differentials; own credit risk; and discount rates. Internally developed correlations and basis differentials are reviewed on a quarterly basis based on statistical analysis of the spot markets in the various illiquid term markets. Discount rates may include a risk premium for those long-term forward contracts with illiquid future price points to incorporate the inherent uncertainty of these points. Any risk premiums for long-term contracts are evaluated by observing similar industry practices and in discussion with industry peers.

The Company uses a modelled pricing valuation technique for determining the FV of Level 3 derivative instruments. The following table outlines quantitative information about the significant unobservable inputs used in the FV measurements categorized within Level 3 of the FV hierarchy:

	September 30, 2025
As at<br> <br>millions of<br>dollars	FV				SignificantUnobservable Input	Low
	Assets		Liabilities
HFT derivatives – Power swaps and physical contracts	****	5	****	4	Third-party pricing	$	27.50	144.40	$79.09
HFT derivatives – Natural gas swaps, futures, forwards and physical contracts	****	38	****	374	Third-party pricing		0.69	15.54	$8.64
Total	$	43	$	378
Net liability			$	335

All values are in US Dollars.

(1) Unobservable inputs were weighted by the relative FV of the instruments.

Long-term debt is a financial liability not measured at FV on the Condensed Consolidated Balance Sheets. The balance consisted of the following:

As at<br> <br>millions of<br>dollars	CarryingAmount		FV		Level 1		Level 2		Level 3		Total
September 30, 2025	$	18,979	$	18,314	$	-	$	17,911	$	403	$	18,314
December 31, 2024	$	18,407	$	17,941	$	-	$	17,688	$	253	$	17,941

The Company has designated $1.2 billion USD denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in USD denominated operations. An after-tax foreign currency loss of $33 million was recorded in AOCI for the three months ended September 30, 2025 (2024 – $22 million after-tax gain) and an after-tax foreign currency gain of $56 million was recorded for the nine months ended September 30, 2025 (2024 – $33 million after-tax loss).

15. RELATED PARTY TRANSACTIONS

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<br>Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $49 million for the three months ended September 30, 2025 (2024 – $41 million) and $140 million for the nine<br>months ended September 30, 2025 (2024 – $123 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.<br>
•	Natural gas transportation capacity purchases from M&NP are reported in the Condensed Consolidated Statements of<br>Income. Purchases from M&NP reported net in Operating revenues – non-regulated, totalled $1 million for the three months ended September 30, 2025 (2024 – $2 million) and<br>$12 million for the nine months ended September 30, 2025 (2024 – $8 million).
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•	On March 5, 2025, NSPI sold development assets associated with the Wasoqonatl transmission line project to WTI for<br>consideration of $15 million. The development assets were sold at cost with no gain or loss recognized in the Condensed Consolidated Statements of Income.
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16. RECEIVABLES AND OTHER CURRENT ASSETS

As at<br> <br>millions of dollars	September 302025
Customer accounts receivable – billed	****	963	$ 834
Customer accounts receivable – unbilled	****	370	342
Capitalized transportation capacity (1)	****	246	216
Cash collateral provided to others	****	142	198
Prepaid expenses	****	133	105
Income tax receivable	****	49	22
Allowance for credit losses	****	(13)	(12)
Other	****	215	106
Total receivables and other current assets	****	2,105	$ 1,811

All values are in US Dollars.

(1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract.

17. EMPLOYEE BENEFIT PLANS

Emera maintains a number of contributory defined-benefit (“DB”) and defined-contribution (“DC”) pension plans, which cover substantially all of its employees. The Company also provides non-pension benefits for its retirees.

Emera’s net periodic benefit cost included the following:

For the	Three months ended<br>September 30				Nine months ended<br>September 30
millions of dollars	2025		2024		2025		2024
DB pension plans
Service cost	$	9	$	9	$	27	$	26
Non-service cost:
Interest cost	****	29		27	****	86		82
Expected return on plan assets	****	(40)		(40)	****	(122)		(120)
Current year amortization of:
Actuarial losses	****	-		-	****	1		1
Regulatory asset	****	2		3	****	7		7
Total non-service costs	****	(9)		(10)	****	(28)		(30)
Total DB pension plans	****	-		(1)	****	(1)		(4)
Non-pension benefit plans
Service cost	****	-		1	****	2		2
Non-service cost:
Interest cost	****	3		3	****	9		9
Expected return on plan assets	****	(1)		(1)	****	(2)		(2)
Current year amortization of:
Regulatory asset	****	-		(1)	****	-		(3)
Past service costs	****	-		-	****	(1)		-
Total non-service costs	****	2		1	****	6		4
Total non-pension benefit plans	****	2		2	****	8		6
Total DB plans	$	2	$	1	$	7	$	2

Emera’s pension and non-pension contributions related to these DB plans for the three months ended September 30, 2025 were $20 million (2024 – $13 million), and for the nine months ended September 30, 2025 were $47 million (2024 – $41 million). Annual employer contributions to the DB pension plans are estimated to be $41 million for 2025. Emera’s contributions related to the DC plans for the three months ended September 30, 2025 were $13 million (2024 – $12 million) and $41 million (2024 – $37 million) for the nine months ended September 30, 2025.

18. SHORT-TERM DEBT

Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non-revolving credit facilities and short-term notes. For details regarding short-term debt, refer to note 24 in Emera’s 2024 annual audited consolidated financial statements, and below for 2025 short-term debt financing activity.

Canadian Electric Utilities

Gas Utilities and Infrastructure

Other

19. LONG-TERM DEBT

For details regarding long-term debt, refer to note 26 in Emera’s 2024 annual audited consolidated financial statements, and below for 2025 long-term debt financing activity.

Florida Electric Utility

On March 6, 2025, TEC issued $600 million USD of senior unsecured notes that bear interest at 5.15 per cent with a maturity date of March 1, 2035.

Other

On September 25, 2025, EUSHI Finance, Emera US Holdings Inc. and Emera filed a shelf registration statement on Form F-10 and Form F-3 (“Registration Statement”), with the Nova Scotia Securities Commission (“NSSC”) and the US Securities and Exchange Commission (“SEC”) under the US/Canada Multijurisdictional Disclosure System. The Registration Statement was filed in connection with the prospective offer and issue by EUSHI Finance of one or more series of senior and/or subordinated unsecured debt securities (“Debt Securities”), in an aggregate principal amount of up to $3 billion USD, during the 25-month period that the short form base shelf prospectus contained in the Registration Statement (“Base Shelf Prospectus”), including any further amendments thereto, remains valid. The Debt Securities may be offered in one or more transactions, at prices, with maturities and on terms to be set forth in one or more prospectus supplements to be filed with the NSSC and the SEC at the time of any such offering.

20. COMMITMENTS AND CONTINGENCIES

A. Commitments

As at September 30, 2025, contractual commitments (excluding pensions and other post-retirement obligations, long-term debt and asset retirement obligations) for each of the next five years and in aggregate thereafter consisted of the following: ****

millions of dollars	2025		2026		2027		2028		2029		Thereafter		Total
Purchased power (1)	$	89	$	316	$	406	$	396	$	445	$	5,951	$	7,603
Transportation (2)(3)		241		725		578		466		407		3,122		5,539
Fuel, gas supply and storage (4)		227		660		130		45		40		99		1,201
Capital projects		342		149		40		5		2		-		538
Other		42		72		58		50		48		264		534
	$	941	$	1,922	$	1,212	$	962	$	942	$	9,436	$	15,415

As detailed below, commitments at September 30, 2025 include those related to NMGC. On completion of the sale of NMGC, all remaining future commitments will be transferred to the buyer. For further details on the pending transaction, refer to note 3.

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

(2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $124 million related to a gas transportation contract between PGS and SeaCoast through 2040.

(3) Includes $65 million related to NMGC (2025: $11 million, 2026: $23 million, 2027: $15 million, 2028: $12 million, 2029: $4 million).

(4) Includes $186 million related to NMGC (2025: $53 million, 2026: $117 million, 2027: $13 million, 2028: $3 million).

B. Legal Proceedings

Superfund and Former Manufactured Gas PlantSites

Previously, TEC had been a potentially responsible party (“PRP”) for certain superfund sites through its Tampa Electric and former PGS divisions, as well as for certain former manufactured gas plant sites through its PGS division. As a result of the separation of the PGS division into a separate legal entity, Peoples Gas System, Inc. is also now a PRP for those sites (in addition to third party PRPs for certain sites). While the aggregate joint and several liability associated with these sites has not changed as a result of the PGS legal separation, the sites continue to present the potential for significant response costs. As at September 30, 2025, the aggregate financial liability of the Florida utilities is estimated to be $16 million ($12 million USD), primarily at PGS. This estimate assumes that other involved PRPs are credit-worthy entities. This amount has been accrued and is primarily reflected in the long-term liability section under “Other long-term liabilities” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.

The estimated amounts represent only the portion of the cleanup costs attributable to the Florida utilities. The estimates to perform the work are based on the Florida utilities’ experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-worthy and are likely to continue to be credit-worthy for the duration of the remediation work. However, in those instances that they are not, the Florida utilities could be liable for more than their actual percentage of the remediation costs. Other factors that could impact these estimates include additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in base rate proceedings.

OtherLegal Proceedings

Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company.

C. Principal Financial Risks and Uncertainties

For information on principal financial risks which could materially affect the Company in the normal course of business, refer to note 28 in Emera’s 2024 annual audited consolidated financial statements. Risks associated with derivative instruments and FV measurements are discussed in note 13 and note 14. There have been no material changes to the principal financial risks as of September 30, 2025.

D. Guarantees and Letters of Credit

Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2024 audited annual consolidated financial statements, with material updates as noted below:

21. CUMULATIVE PREFERREDSTOCK

For details regarding cumulative preferred stock, refer to note 29 in Emera’s 2024 annual audited consolidated financial statements, and below for 2025 preferred stock activity.

22. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the	Nine months ended September 30
millions of dollars	2025		2024
Changes in non-cash working capital:
Inventory	$	(84)	$	44
Receivables and other current assets	****	(230)		155
Accounts payable	****	(169)		(64)
Other current liabilities	****	101		85
Total non-cash working capital	$	(382)	$	220
Supplemental disclosure of non-cash activities:
Common share dividends reinvested	$	225	$	217
Increase in accrued capital expenditures	$	28	$	12
Accrued proceeds from disposal of investment subject to significant influence	$	-	$	25
Supplemental disclosure of operating activities:
Net change in short-term regulatory assets and liabilities	$	217	$	216

23. VARIABLE INTEREST ENTITIES

Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since it does not have controlling financial interest of NSPML. When the critical milestones were achieved, Newfoundland and Labrador Hydro was deemed the primary beneficiary of the asset for financial reporting purposes, as it has authority over the majority of the direct activities expected to most significantly impact the economic performance of the Maritime Link. Thus, Emera began recording the Maritime Link as an equity investment.

BLPC established a SIF, primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission, and distribution systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered that, in substance, activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. Any withdrawal of SIF fund assets by the Company would be subject to existing regulations. Emera’s consolidated VIE in the SIF is recorded as “Other long-term assets”, “Restricted cash” and “Regulatory liabilities” on the Condensed Consolidated Balance Sheets. Amounts included in restricted cash represent the cash portion of funds required to be set aside for the BLPC SIF.

The Company has identified certain long-term purchase power agreements that meet the definition of variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions.

The following table provides information about Emera’s portion of material unconsolidated VIEs:

As at	September 30, 2025				December 31, 2024
millions of dollars	Total<br><br><br>assets		Maximum<br><br><br>exposure to<br> <br>loss		Total<br>assets		Maximum<br><br><br>exposure to<br> <br>loss
Unconsolidated VIEs in which Emera has variable interests
NSPML (equity accounted)	$	470	$	6	$	475	$	6

24. SUBSEQUENT EVENTS

These unaudited condensed consolidated interim financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through November 7, 2025, the date the unaudited condensed consolidated interim financial statements were issued.

EX-99.3

Exhibit 99.3

Emera Incorporated

Earnings Coverage Ratio

Pursuant to Section 8.4 of National Instrument 44-102, this updated calculation of the earnings coverage ratio is filed as an exhibit to the unaudited condensed consolidated interim financial statements of Emera Incorporated (“Emera”) for the nine months ended September 30, 2025.

The following earnings coverage ratio is calculated on a consolidated basis for the twelve months ended September 30, 2025.

	Twelve months ended<br>September 30, 2025
Earnings Coverage ^(1)^	1.83

^(1)^ Earnings coverage is equal to consolidated net income attributable to common shareholders plus: income taxes, interest on debt, amortization of debt financing costs, allowance for funds used during construction and preferred share dividends declared during the period together with undeclared preferred share dividends, if any, divided by the sum of interest on debt, amortization of debt financing costs, allowance for funds used during construction, capitalized interest and preferred dividends grossed up to a before-tax equivalent using an effective tax rate of 29.0 per cent.

Emera’s dividend requirements on all of its preferred shares, grossed up to a before-tax equivalent using an effective income tax rate of 29.0 per cent, amounted to $104 million **** for the twelve months ended September 30, 2025. Emera’s interest requirements for the twelve months ended September 30, 2025 amounted to $1,044 million. Emera’s consolidated income before interest and income tax for the twelve months ended September 30, 2025 was $2,105 million, which is 1.83 times Emera’s aggregate preferred dividends and interest requirements for this period.

EX-99.4

Exhibit 99.4

LOGO

Emera Reports 2025 Third Quarter Financial Results andUnveils $20 Billion Five-Year Capital Plan

HALIFAX, Nova Scotia – Today, November 7, 2025, Emera Inc. (“Emera”) (TSX/NYSE: EMA) reported financial results for the third quarter and year-to-date 2025 and released details about its 2026-2030 capital plan.

Highlights

•	Delivered 9% improvement in adjusted earnings per share^1^<br>(“EPS”) for the third quarter of 2025, with $0.88 of adjusted EPS and $0.76 of reported EPS.
•	Introduced 5-year $20 billion capital plan and extended 7-8% rate base growth guidance through 2030 with approximately 80% directed towards investment in Florida.
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•	Completed the Peoples Gas rate case process, providing regulatory clarity through 2028. Nova Scotia Power reached a<br>settlement agreement with customer representatives, and a consensus rate case was filed with the regulator in mid-September.
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•	Deployed more than $2.6 billion in capital<br>year-to-date and remain on track to fully execute our 2025 capital plan.
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“Emera’s momentum continues with another strong quarter of adjusted EPS^1^ growth, principally driven by continued strong operational performance at Tampa Electric. We also saw significant progress on the regulatory front with the completion of the Peoples Gas rate case,” said Scott Balfour, President and CEO of Emera Inc. “We are extending our 7-8% rate base growth through 2030, supported by a $20 billion capital plan that focuses on enhancing customer reliability. This includes investments in grid modernization, gas infrastructure and technology updates that will support ongoing growth, with a specific focus on Florida.”

5-Year Capital and Funding Plan Overview

•	Five-year $20 billion capital and funding plan extends 7-8% rate<br>base growth guidance through 2030.
•	Emera’s capital plan is primarily directed toward investments in Florida, with nearly 80% allocated to<br>the region focused on strengthening and storm hardening systems and supporting continued growth, while continuing to deliver an 8-9% expected rate base growth for its Florida utilities.
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LOGO

•	The majority of capital plan – more than 90% - is allocated to reliability and grid modernization projects;<br>renewable asset integration (for greater reliability and more predictable customer costs); and technological innovation (including increased investments in cybersecurity and artificial intelligence).
•	55% of investments specifically focused on strengthening electric transmission, distribution, and gasinfrastructure systems to support reliability and customer growth.
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Q3 2025 Financial Results

Q3 2025 adjusted net income^1^ was $263 million, or $0.88 per common share, compared with $236 million, or $0.81 per common share, in Q3 2024. The increase was primarily due to increased earnings at Tampa Electric (“TEC”), partially offset by lower earnings at Nova Scotia Power (“NSPI”) and New Mexico Gas Company (“NMGC”) and higher corporate costs.

Q3 2025 reported net income was $228 million, or $0.76 per common share, compared with net income of $4 million, or $0.01 per common share, in Q3 2024, primarily driven by the $225 million in charges related to the pending sale of NMGC recognized in Q3 2024, and increased earnings at TEC. These were partially offset by $28 million increase in mark-to-market (“MTM”) losses, lower earnings at NSPI and NMGC, and higher corporate costs.

Year-to-date Financial Results

Year-to-date adjusted net income^1^ was $878 million or $2.94 per common share, compared with $603 million or $2.10 per common share year-to-date in 2024. Year-to-date adjusted net income increased $275 million primarily due to increased earnings at TEC, Emera Energy Services (“EES”), NSPI, and NMGC; and decreased corporate costs. These were partially offset by lower equity earnings resulting from last year’s sale of Emera’s interest in the Labrador Island Link (“LIL”).

Year-to-date reported net income was $946 million or $3.17 per common share, compared with net income of $340 million or $1.18 per common share, year-to-date in 2024. Year-to-date reported net income included a $140 million MTM gain, after-tax, compared to a $145 million MTM loss, after-tax in 2024, and $72 million in charges related to the pending sale of NMGC, after-tax. Year-to-date reported income for 2024 included a $107 million gain, after tax and transaction costs, on the sale of Emera’s equity interest in LIL in Q2 2024 and $225 million in charges related to the pending sale of NMGC in Q3 2024.

The translation impact of a weaker CAD on USD earnings increased adjusted net income by $1 million in Q3 2025 and $16 million year-to-date compared to the same periods in 2024.

LOGO

In Q3 2025, 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 $10 million decrease to net income attributable to common shareholders compared to the same period in 2024. Year-to-date 2025, the impact of a weaker CAD on US denominated earnings increased net income attributable to common shareholders by $52 million compared to the same period in 2024. 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.

(1)	See “Non-GAAP Financial Measures and Ratios” noted below and<br>“Segment Results and Non-GAAP Reconciliation” below for reconciliation to nearest USGAAP measure.

LOGO

Segment Results andNon-GAAP Reconciliation

For the	Three months ended<br><br><br>September 30				Nine months ended<br><br><br>September 30
millions of Canadian dollars (except per share amounts)	2025		2024		2025		2024
Adjusted net income ^1,2^
Florida Electric Utility	$	302	$	252	****	726		524
Canadian Electric Utilities	****	13		26	****	151		155
Gas Utilities and Infrastructure	****	32		38	****	200		180
Other Electric Utilities	****	16		10	****	28		27
Other ^3^	****	(100)		(90)	****	(227)		(283)
Adjusted net income^1^^,2^	$	263	$	236	****	878		603
Charges related to the pending sale of NMGC,<br>after-tax ^4,5^	****	-		(225)	****	(72)		(225)
Gain on sale of LIL, after-tax ^6^	****	-		-	****	-		107
MTM (loss) gain, after-tax^7^	****	(35)		(7)	****	140		(145)
Net income attributable to common shareholders	$	228	$	4	****	946		340
EPS (basic)	$	0.76	$	0.01	****	3.17		1.18
Adjusted EPS (basic) ^1,2^	$	0.88	$	0.81	****	2.94		2.10

^1^ See “Non-GAAPFinancial Measures and Ratios” noted below.

^2^ Excludes the charges related tothe pending sale of NMGC, after-tax, gain on sale of LIL, after-tax, and the effect of after-tax MTM adjustments.

^3^ Lower earnings, quarter-over-quarter, primarily results from higher operating, maintenanceand general expenses (“OM&G”), partially offset by higher income tax recovery. Higher earnings year-over-year due to higher contributions from EES, lower OM&G and higher income tax recovery, partially offset higher interestexpense.

^4^ Represents (i) a $71 millionnon-cash impairment charge, after-tax, and $1 million in transaction costs, after-tax for the nine months endedSeptember 30, 2025 and (ii) $206 million in non-cash goodwill and other impairment charges, after-tax and $19 million in transaction costs, after-tax for the three and nine months ended September 30, 2024.

^5^ Net of income tax recovery of nil for the three months ended September 30, 2025 (2024 - $20 million) and $5 million for the nine months ended September 30, 2025 (2024 - $20 million).

^6^ Net of income tax expense of $75 million for the nine months ended September30, 2024.

^7^ Net of income tax recovery of $15 million for the three months endedSeptember 30, 2025 (2024 – $4 million recovery) and $56 million income tax expense for the nine months ended September 30, 2025 (2024 – $60 million recovery).

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Consolidated Financial Review

The following table highlights significant quarter-over-quarter and year-over-year changes in adjusted net income from 2024 to 2025:

For the<br><br><br>millions of Canadian dollars	Three months ended<br><br><br>September 30		Nine months ended<br><br><br>September 30
Adjusted net income – 2024^1,2^	$	236	$	603
Operating Unit Performance
Increased earnings at TEC due to higher revenue from new base rates and customer growth, partially offset by increased OM&G, depreciation expenses, interest and income tax expense.<br>Year-over-year the increase was also due to the impact of favourable weather and the impact of a weaker CAD		50		202
Decreased income from equity investments due to the sale of equity interest in LIL in Q2 2024		-		(28)
Increased earnings at EES year-over-year due to favourable weather and resulting market conditions in Q1 2025 (higher natural gas prices and increased<br>volatility)		(1)		33
Increased earnings year-over-year at NMGC due to higher revenue from new base rates and the impact of a weaker CAD		(4)		22
Decreased earnings quarter-over-quarter at NSPI due to increased OM&G and higher depreciation expense. Increased earnings year-over-year due to<br>investment tax credits related to clean technology investments and increased sales volumes driven by favourable weather, partially offset by higher OM&G and higher depreciation expense		(11)		30
Corporate
Increased income tax recovery due to decreased deferred income tax asset valuation allowance and increased loss before provision for income taxes		11		18
Increased interest expense primarily due to increased total debt, partially offset by lower interest rates		(3)		(10)
Increased OM&G quarter-over-quarter and decreased year-over-year primarily due to timing of the recognition on long term compensation expense and related<br>hedges		(16)		8
Other Variances		1		-
Adjusted net income – 2025 ^1,2^	$	263	$	878

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^1^ See “Non-GAAP Financial Measures and Ratios” noted below and “Segment Results and Non-GAAPReconciliation” for reconciliation to nearest GAAP measure.

^2^ Excludes thecharges related to the pending sale of NMGC, after-tax, gain on sale of LIL, after-tax, and the effect of after-tax MTMadjustments.

^1^ Non-GAAP Financial Measures and Ratios

Emera uses financial measures that do not have standardized meaning under USGAAP and may not be comparable to similar measures presented by other entities. Emera calculates the non-GAAP measures and ratios by adjusting certain GAAP measures for specific items. Management believes excluding these items better distinguishes the ongoing operations of the business. For further information on the non-GAAP financial measure, adjusted net income, and the non-GAAP ratio, adjusted EPS – basic, refer to the “Non-GAAP Financial Measures and Ratios” section of Emera’s Q3 2025 MD&A, which is incorporated herein by reference and can be found on SEDAR+ at www.sedarplus.ca. Reconciliation to the nearest GAAP measure is included in “Segment Results and Non-GAAP Reconciliation” above.

Forward-LookingInformation

This news release contains forward-looking information or forward-looking statements within the meaning of applicable securities laws (collectively, “forward-looking information”), including without limitation, statements about the Company’s expectations regarding future growth, including the extension of its 7% to 8% rate base growth guidance through 2030, the nature and timing of its $20 billion capital and funding plan and its expectations that 80% of the capital plan will be invested in Florida, its expectations for 8% to 9% rate base growth for its Florida utilities, its plans to allocate more than 90% of its capital investments to reliability, grid modernization, renewable asset integration and technological innovation, and its intention to focus 55% of capital investments on strengthening transmission, distribution and gas infrastructure systems to support reliability and customer growth. By its nature, forward-looking information requires Emera to make assumptions and is subject to inherent risks and uncertainties. These statements reflect Emera management’s current beliefs and are based on information currently available to Emera management. There is a risk that predictions, forecasts, conclusions and projections that constitute forward-looking information will not prove to be accurate, that Emera’s assumptions may not be correct and that actual results may differ materially from those expressed or implied by such forward-looking information. Additional detailed information about these assumptions, risks and uncertainties is included in Emera’s securities regulatory filings, including under the heading “Business Risks and Risk Management” in Emera’s annual Management’s Discussion and Analysis, and under the heading “Principal Risks and Uncertainties” in the notes to Emera’s annual and interim financial statements, which can be found on SEDAR+ at www.sedarplus.ca or on EDGAR at www.sec.gov. The forward-looking information in this news release is made only as of the

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date of thereof, and Emera disclaims any intention or obligation to update or revise any forward-looking information.

Teleconference Call

The company will be hosting a teleconference today, Friday, November 7, at 9:30 a.m. Atlantic (8:30 a.m. Eastern) to discuss the Q3 2025 financial results.

Analysts and other interested parties in North America are invited to participate by dialing 1-800-717-1738. International parties are invited to participate by dialing 1-289-514-5100. Participants should dial in at least 10 minutes prior to the start of the call. No pass code is required.

A live and archived audio webcast of the teleconference will be available on the Company’s website, www.emera.com. A replay of the teleconference will be available on the Company’s website two hours after the conclusion of the call.

About Emera

Emera (TSX/NYSE: EMA) is a leading North American provider of energy services headquartered in Halifax, Nova Scotia, with investments in regulated electric and natural gas utilities, and related businesses and assets. The Emera family of companies delivers safe, reliable energy to approximately 2.6 million customers in Canada, the United States and the Caribbean. Our team of 7,600 employees is committed to our purpose of energizing modern life and delivering a cleaner energy future for all. Emera’s common and preferred shares are listed and trade on the Toronto Stock Exchange and its common shares are listed and trade on the New York Stock Exchange. Additional information can be accessed at www.emera.com, on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov.

Emera Inc.

Investor Relations

Dave Bezanson, VP, Investor Relations & Pensions 902-233-2674

[email protected]

Media

[email protected]

EX-99.5

Exhibit 99.5

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

I, Scott Balfour, President and Chief Executive Officer of Emera Incorporated, **** certify the following:

Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Emera Incorporated (the “issuer”) for the interim period ended September 30, 2025.
No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.
Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.
Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and InterimFilings, for the issuer.
Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings

A.	designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that<br>
i.	material information relating to the issuer is made known to us by others, particularly during the period in which the<br>interim filings are being prepared; and
---	---
ii.	information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or<br>submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and
---	---
B.	designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the<br>reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.
---	---

5.1 Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (COSO) Internal Control-Integrated Framework.

5.2 ***ICFR – material weakness relating to design:***N/A

5.3 Limitation on scope of design: The issuer has disclosed in its interim MD&A

a.	the fact that the issuer’s other certifying officer(s) and I have limited the scope of our design of DC&P and<br>ICFR to exclude controls, policies and procedures of:
i.	a proportionately consolidated entity in which the issuer has an interest;
---	---
ii.	a special purpose entity in which the issuer has an interest; or
---	---
iii.	a business that the issuer acquired not more than 365 days before the last day of the period covered by the interim<br>filings; and
---	---
b.	summary financial information about the proportionately consolidated entity, special purpose entity or business that the<br>issuer acquired that has been proportionately consolidated or consolidated in the issuer’s financial statements.
---	---

Reporting changesin ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on July 1, 2025 and ended on September 30, 2025 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: November 7, 2025
“Scott Balfour”
Scott Balfour
President and Chief Executive Officer

EX-99.6

Exhibit 99.6

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

I, Greg Blunden, Chief Financial Officer of Emera Incorporated, **** certify the following:

Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Emera Incorporated (the “issuer”) for the interim period ended September 30, 2025.
No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.
Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.
Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and InterimFilings, for the issuer.
Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings

A.	designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that<br>
i.	material information relating to the issuer is made known to us by others, particularly during the period in which the<br>interim filings are being prepared; and
---	---
ii.	information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or<br>submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and
---	---
B.	designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the<br>reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.
---	---

5.2 ***ICFR – material weakness relating to design:***N/A

5.3 Limitation on scope of design: The issuer has disclosed in its interim MD&A

a.	the fact that the issuer’s other certifying officer(s) and I have limited the scope of our design of DC&P and<br>ICFR to exclude controls, policies and procedures of:
i.	a proportionately consolidated entity in which the issuer has an interest;
---	---
ii.	a special purpose entity in which the issuer has an interest; or
---	---
iii.	a business that the issuer acquired not more than 365 days before the last day of the period covered by the interim<br>filings; and
---	---
b.	summary financial information about the proportionately consolidated entity, special purpose entity or business that the<br>issuer acquired that has been proportionately consolidated or consolidated in the issuer’s financial statements.
---	---

Reporting changesin ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on July 1, 2025 and ended on September 30, 2025 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: November 7, 2025
“Greg Blunden”
Greg Blunden
Chief Financial Officer