EX-99.1

EX-99.1 2 d818790dex991.htm EX-99.1 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
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 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 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”) commodity derivative instruments, including adjustments related to the price differential between the point where natural gas is sourced and where it is delivered, and the related amortization of transportation capacity recognized as a result of certain Emera Energy marketing and trading transactions;

•

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

•

equity securities held in BLPC and Emera Energy; and

•

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

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 Indirect Minority 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 Income Attributable to Common Shareholders to Adjusted Net Income


For the	Three months ended September 30				Nine months ended September 30
millions of dollars (except per share amounts)	2025		2024		2025		2024
Net income attributable to common 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, 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, 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 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 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 nine months ended September 30, 2025 (2024 – $60 million recovery).

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 September 30				Nine months ended 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: Charges related to the pending sale of NMGC, excluding 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 Sale of 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 millions of dollars	Three months ended September 30				Nine months ended 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, after-tax		-		-		-		107
MTM (loss) gain, after-tax		(35)		(7)		140		(145)
Net income attributable to common 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”), 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 (“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 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 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 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 shareholders	$	228	$	4	$	224	$	946	$	340	$	606
Adjusted net income	$	263	$	236	$	27	$	878	$	603	$	275
Weighted average shares of common 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 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 September 30				Nine months ended September 30				Year ended 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:


	Three months ended						Nine months ended
For the	September 30						September 30
millions of USD	2025			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 USD adjusted net income from PGS, NMGC, SeaCoast and M&NP.
(2) Excludes $6 million USD after-tax in other impairment charges associated with the pending sale of NMGC for the three and nine months ended September 30, 2024.
(3) Includes Emera Energy’s USD adjusted net income from EES, Bear Swamp and interest expense on Emera Inc.’s USD denominated debt.
(4) Excludes $20 million USD MTM loss, after-tax, for the three months ended September 30, 2025 (2024 – $183 million USD MTM loss, after-tax) and $78 million USD MTM gain, after-tax, for the nine months ended September 30, 2025 (2024 – $272 million USD MTM loss, after-tax).

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.

Other Electric 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 Increase (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 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 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 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 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 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 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 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 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 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 September 30				Nine months ended September 30
millions of USD (except as indicated)	2025		2024		2025		2024
Operating revenues – regulated electric	$	921	$	724	$	2,409	$	1,944
Regulated fuel for generation and purchased power	$	204	$	164	$	553	$	471
Contribution to consolidated net income	$	220	$	186	$	522	$	385
Contribution to consolidated net income – CAD	$	302	$	252	$	726	$	524
Electric sales volumes (Gigawatt hours (“GWh”))		6,270		6,437		16,306		16,080
Electric production volumes (GWh)		6,589		6,661		17,150		17,017
Average fuel cost in dollars per 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	Three months ended		Nine months ended
millions of USD	September 30		September 30
Contribution to consolidated net 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 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 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 also partially offset by higher benefit from production tax credits		(10)		(34)
Other		(6)		(4)
Contribution to consolidated net income – 2025	$	220	$	522

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 electric	$	405	$	399	$	1,440	$	1,376
Regulated fuel for generation and purchased power (1)	$	222	$	243	$	796	$	725
Contribution to consolidated net income	$	13	$	26	$	151	$	155
Electric sales volumes (GWh)		2,230		2,285		7,936		7,849
Electric production volumes (GWh)		2,380		2,428		8,466		8,361
Average fuel costs in dollars per 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 net income	$	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 net income – 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 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 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 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 net income – 2025	$	13	$	151

Gas Utilities and Infrastructure


	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 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 net income	$	23	$	28		$	141	$	133
Contribution to consolidated adjusted net income – CAD	$	32	$	38		$	200	$	180
Charges related to the pending sale of NMGC, after-tax (2)		-		(6	)		-		(6	)
Contribution to consolidated net income	$	23	$	22		$	141	$	127
Contribution to consolidated net income – CAD	$	32	$	30		$	200	$	172
Gas sales volumes (millions of 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 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.

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 consolidated adjusted 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 consolidated net 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 electric	$	115	$	110	$	311	$	306
Regulated fuel for generation and purchased power	$	60	$	58	$	160	$	160
Contribution to consolidated adjusted net income	$	11	$	8	$	20	$	20
Contribution to consolidated adjusted net income – CAD	$	16	$	10	$	28	$	27
Equity securities MTM gain	$	-	$	-	$	1	$	1
Contribution to consolidated net income	$	11	$	8	$	21	$	21
Contribution to consolidated net income – CAD	$	16	$	11	$	30	$	29
Electric sales volumes (GWh)		349		346		977		984
Electric production volumes (GWh)		377		371		1,045		1,056
Average fuel costs in dollars per MWh	$	159	$	156	$	153	$	152

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


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

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	Three months ended		Nine months ended
millions of USD	September 30		September 30
Contribution to consolidated net income – 2024	$	8	$	21
Increased operating revenues – regulated electric due to higher fuel revenue at GBPC and higher miscellaneous revenue at BLPC		5		5
Increased regulated fuel for generation and purchased power due to higher fuel costs at GBPC		(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 income – 2025	$	11	$	21

Other


	Three months ended				Nine months ended
For the	September 30				September 30
millions of dollars	2025		2024		2025		2024
Marketing and trading margin (1)(2)	$	(3)	$	(7)	$	98	$	42
Other non-regulated operating revenue		9		7		25		22
Total operating revenues – non-regulated	$	6	$	-	$	123	$	64
Contribution to consolidated adjusted net (loss) income	$	(100)	$	(90)	$	(227)	$	(283)
Charges related to the pending sale of NMGC, after-tax (3)		-		(217)		(72)		(217)
Gain on sale of LIL, after-tax (4)(5)		-		-		-		107
MTM (loss) gain, after-tax (6)		(35)		(8)		138		(147)
Contribution to consolidated net (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 consolidated adjusted 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, 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 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 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 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 (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	Maturity		Credit Facilities		Utilized		Undrawn and Available
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 facility		May 2026		500		500		-
Emera – non-revolving facility		February 2026		200		200		-
In USD:
TEC – committed revolving credit facility		December 2028		800		511		289
TECO Finance, Inc. – committed revolving credit 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

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.

Credit Ratings

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, 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 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 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 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, refer to the “Contractual Obligations” section.

•

Natural gas transportation capacity purchases from M&NP are reported in the Condensed Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues – non-regulated, totalled $1 million for the three months ended September 30, 2025 (2024 – $2 million) and $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 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 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 ACCOUNTING POLICIES AND PRACTICES

Future Accounting Pronouncements

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

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 Statement Expenses

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

Improvements to Income Tax Disclosures

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

SUMMARY OF QUARTERLY RESULTS


For the quarter ended 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.