EX-99.2

EX-99.2 3 d818790dex992.htm EX-99.2 EX-99.2

Exhibit 99.2

EMERA INCORPORATED

Unaudited Condensed Consolidated

Interim Financial Statements

September 30, 2025 and 2024

Emera Incorporated

Condensed Consolidated Statements of Income (Unaudited)


	Three months ended				Nine months ended
For the		September 30				September 30
millions of dollars (except per share amounts)		2025		2024		2025		2024

Operating revenues
Regulated electric	$	1,829	$	1,534	$	5,227	$	4,431
Regulated gas		308		291		1,264		1,134
Non-regulated		(31)		(23)		279		(128)
Total operating revenues (note 5)		2,106		1,802		6,770		5,437

Operating expenses
Regulated fuel for generation and purchased power		547		484		1,653		1,487
Regulated cost of natural gas		53		46		346		282
Operating, maintenance and general expenses (“OM&G”)		578		432		1,673		1,415
Provincial, state and municipal taxes		124		110		364		325
Depreciation and amortization		324		293		959		866
Impairment charges (note 3)		-		221		75		221
Total operating expenses		1,626		1,586		5,070		4,596
Income from operations		480		216		1,700		841

Income from equity investments (note 7)		15		25		48		87
Other income, net (note 8)		19		14		135		232
Interest expense, net		260		241		764		725
Income before provision for income taxes		254		14		1,119		435

Income tax expense (recovery) (note 9)		6		(9)		116		40
Net income		248		23		1,003		395

Non-controlling interest in subsidiaries (“NCI”)		1		1		1		1
Preferred stock dividends		19		18		56		54
Net income attributable to common shareholders	$	228	$	4	$	946	$	340

Weighted average shares of common stock outstanding (in millions) (note 11)
Basic		299.9		290.0		298.5		287.5
Diluted		300.6		290.1		299.0		287.6

Earnings per common share (note 11)
Basic	$	0.76	$	0.01	$	3.17	$	1.18
Diluted	$	0.76	$	0.01	$	3.16	$	1.18

Dividends per common share declared	$	0.7250	$	0.7175	$	2.1750	$	2.1525

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

Emera Incorporated

Condensed Consolidated Statements of Comprehensive Income (Unaudited)


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

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

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

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

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited)


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

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

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited) – Continued


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

Commitments and contingencies (note 20)

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

Approved on behalf of the Board of Directors

“Karen Sheriff” “Scott Balfour”

Chair of the Board President and Chief Executive Officer

Emera Incorporated

Condensed Consolidated Statements of Cash Flows (Unaudited)


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

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

Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)


	Common		Preferred		Contributed				Retained				Total
millions of dollars		Stock		Stock		Surplus		AOCI		Earnings		NCI		Equity
For the three months ended September 30, 2025
Balance, June 30, 2025	$	9,228	$	1,422	$	85	$	660	$	1,755	$	14	$	13,164
Net income of Emera Incorporated		-		-		-		-		247		1		248
OCI, net of tax expense of $3 million		-		-		-		225		-		-		225
Dividends declared on preferred stock (1)		-		-		-		-		(19)		-		(19)
Dividends declared on common stock ($0.7250/share)		-		-		-		-		(217)		-		(217)
Issued under the Dividend Reinvestment Program (“DRIP”), net of discounts		72		-		-		-		-		-		72
Senior management stock options exercised and Employee Common Share Purchase Plan (“ECSPP”)		11		-		-		-		-		-		11
Other		1		-		-		-		-		(1)		-
Balance, September 30, 2025	$	9,312	$	1,422	$	85	$	885	$	1,766	$	14	$	13,484

For the nine months ended September 30, 2025
Balance, December 31, 2024	$	9,042	$	1,422	$	84	$	1,261	$	1,468	$	14	$	13,291
Net income of Emera Incorporated		-		-		-		-		1,002		1		1,003
OCI, net of tax recovery of $6 million		-		-		-		(376)		-		-		(376)
Dividends declared on preferred stock (2)		-		-		-		-		(56)		-		(56)
Dividends declared on common stock ($2.1750/share)		-		-		-		-		(648)		-		(648)
Issued under the DRIP, net of discounts		225		-		-		-		-		-		225
Issuance of common stock under the at-the-market (“ATM”) program, net of after-tax issuance costs		10		-		-		-		-		-		10
Senior management stock options exercised and ECSPP		34		-		1		-		-		-		35
Other		1		-		-		-		-		(1)		-
Balance, September 30, 2025	$	9,312	$	1,422	$	85	$	885	$	1,766	$	14	$	13,484

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

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

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

Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)


	Common		Preferred		Contributed				Retained				Total
millions of dollars		Stock		Stock		Surplus		AOCI		Earnings		NCI		Equity
For the three months ended September 30, 2024
Balance, June 30, 2024	$	8,657	$	1,422	$	83	$	656	$	1,729	$	14	$	12,561
Net income of Emera Incorporated		-		-		-		-		22		1		23
OCI, net of tax recovery of $2 million		-		-		-		(144)		-		-		(144)
Dividends declared on preferred stock (1)		-		-		-		-		(18)		-		(18)
Dividends declared on common stock ($0.7175/share)		-		-		-		-		(207)		-		(207)
Issued under the DRIP, net of discounts		75		-		-		-		-		-		75
Issuance of common stock under the ATM program, net of after-tax issuance costs		146		-		-		-		-		-		146
Senior management stock options exercised and ECSPP		6		-		1		-		-		-		7
Other		-		-		-		-		-		(1)		(1)
Balance, September 30, 2024	$	8,884	$	1,422	$	84	$	512	$	1,526	$	14	$	12,442

For the nine months ended September 30, 2024
Balance, December 31, 2023	$	8,462	$	1,422	$	82	$	305	$	1,803	$	14	$	12,088
Net income of Emera Incorporated		-		-		-		-		394		1		395
OCI, net of tax expense of $3 million		-		-		-		207		-		-		207
Dividends declared on preferred stock (2)		-		-		-		-		(54)		-		(54)
Dividends declared on common stock ($2.1525/share)		-		-		-		-		(617)		-		(617)
Issued under the DRIP, net of discount		217		-		-		-		-		-		217
Issuance under ATM program, net of after-tax issuance costs		181		-		-		-		-		-		181
Senior management stock options exercised and ECSPP		24		-		2		-		-		-		26
Other		-		-		-		-		-		(1)		(1)
Balance, September 30, 2024	$	8,884	$	1,422	$	84	$	512	$	1,526	$	14	$	12,442

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

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

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

Emera Incorporated

Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)

As at September 30, 2025 and 2024

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

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

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

•

Florida Electric Utility, which consists of Tampa Electric (“TEC”), a vertically integrated regulated electric utility in West Central Florida.

•

Canadian Electric Utilities, which includes:

•

NSPI, a vertically integrated regulated electric utility and the primary electricity supplier in Nova Scotia;

•

a 100 per cent equity interest in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link Project, a $1.8 billion, including AFUDC, transmission project between the island of Newfoundland and Nova Scotia; and

•

A 50 per cent indirect voting equity interest in Wasoqonatl Transmission Incorporated (“WTI”), a transmission line project to create a reliability intertie between Nova Scotia and New Brunswick. For more information, refer to note 7.

•

Gas Utilities and Infrastructure, which includes:

•

Peoples Gas System, Inc. (“PGS”), a regulated gas distribution utility operating across Florida;

•

New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility serving customers in New Mexico. On August 5, 2024, Emera announced an agreement to sell NMGC. The transaction is expected to close in early 2026, subject to certain approvals, including approval by the New Mexico Public Regulation Commission (“NMPRC”). For more information on the pending transaction, refer to note 3;

•

Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick to the United States (“US”) border under a 25-year firm service agreement with Repsol Energy North America Canada Partnership (“Repsol Energy”), which expires in 2034;

•

SeaCoast Gas Transmission, LLC (“SeaCoast”), a regulated intrastate natural gas transmission company offering services in Florida; and

•

a 12.9 per cent equity interest in Maritimes & Northeast Pipeline (“M&NP”), a 1,400-kilometre pipeline that transports natural gas throughout markets in Atlantic Canada and the northeastern US.

•

Other Electric Utilities, which includes Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities that include:

•

The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated regulated electric utility on the island of Barbados;

•

Grand Bahama Power Company Limited (“GBPC”), a vertically integrated regulated electric utility on Grand Bahama Island; and

•

a 19.5 per cent equity interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility on the island of St. Lucia.

•

Emera’s other segment includes investments in energy-related non-regulated companies that are below the required threshold for reporting as separate segments and corporate expense and revenue items that are not directly allocated to the operations of Emera’s subsidiaries and investments. This includes:

•

Emera Energy, which consists of:

•

Emera Energy Services (“EES”), a physical energy business that purchases and sells natural gas and electricity and provides related energy asset management services;

•

Brooklyn Power Corporation (“Brooklyn Energy”), a 30 MW biomass co-generation electricity facility in Brooklyn, Nova Scotia; and

•

a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a 660 MW pumped storage hydroelectric facility in northwestern Massachusetts.

•

Emera US Finance LP, EUSHI Finance, Inc. (“EUSHI Finance”), and TECO Finance, Inc., financing subsidiaries of Emera;

•

Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the US; and

•

Other investments.

Basis of Presentation

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

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

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

Use of Management Estimates

The preparation of unaudited condensed consolidated interim financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. In Q2 2025, the Company recognized a $75 million ($55 million USD), pre-tax, non-cash impairment charge related to the pending sale of NMGC. For more information on the impairment charge, refer to note 3. There were no other material changes in the nature of the Company’s critical accounting estimates from those disclosed in Emera’s 2024 annual audited consolidated financial statements.

Seasonal Nature of Operations

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

Cybersecurity Incident

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

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. The Company maintains cyber insurance coverage and is working with its insurer on the claims process.

2. 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.

3. DISPOSITIONS

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.

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

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

Following the goodwill impairment assessment, the held for sale assets and liabilities were measured at the lower of their carrying amount or fair value less costs to sell. The measurement resulted in an additional loss for the estimated future transaction costs of $16 million ($13 million after-tax), in addition to

incurred transaction costs of $8 million ($6 million after-tax) recorded in “Other income, net” on the Condensed Consolidated Statements of Income in Q3 2024.

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

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.

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


As at millions of dollars	September 30 2025		December 31 2024

Cash and cash equivalents	$	3	$	8

Inventory		9		9

Derivative instruments		5		1

Regulatory assets		32		28

Receivables and other current assets		75		127

Current assets held for sale	$	124	$	173

PP&E		1,865		1,845

Regulatory assets		8		6

Goodwill		292		303

Other long-term assets		26		23

Less: Adjustment to FV less costs to sell (1)		(91)		(17)

Long-term assets held for sale	$	2,100	$	2,160

Total assets held for sale	$	2,224	$	2,333


Short-term debt	$	114	$	46

Current portion of long-term debt		97		-

Derivative instruments		-		1

Regulatory liabilities		15		10

Accounts payable and other current liabilities		97		155

Current liabilities associated with assets held for sale		323		212

Long-term debt		576		696

Deferred income taxes		189		167

Regulatory liabilities		265		274

Other long-term liabilities		7		11

Long-term liabilities associated with assets held for sale	$	1,037	$	1,148

Total liabilities associated with assets held for sale	$	1,360	$	1,360

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

Sale of LIL Equity Interest

On June 4, 2024, Emera completed the sale of its 31.1 per cent indirect minority equity interest in the LIL for a total transaction value of $1.2 billion, including cash proceeds of $957 million and $235 million for assuming Emera’s contractual obligation to fund the remaining initial capital investment, which represents additional LIL equity interest for the acquirer. Cash proceeds from the sale in the amount of $30 million is held in escrow pending finalization of certain agreements with the LIL general partner. The escrow proceeds receivable is held at FV and included in the gain on sale, after transaction costs. As of September 30, 2025, the estimated FV of the escrow proceeds receivable is $25 million. In Q2 2024, a gain on sale, after transaction costs, of $182 million ($107 million, after tax and transaction costs), was recognized in “Other income, net” on the Condensed Consolidated Statements of Income and included in the Other segment.

4. SEGMENT INFORMATION

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


millions of dollars	Florida Electric Utility		Canadian Electric Utilities			Gas Utilities and Infrastructure		Other Electric Utilities		Other			Inter- Segment Eliminations			Total

For the three months ended September 30, 2025
Operating revenues from external customers (1)	$	1,266	$	405		$	314	$	159	$	(38	)	$	-		$	2,106

Inter-segment revenues (1)		3		-			5		-		7			(15	)		-

Total operating revenues		1,269		405			319		159		(31	)		(15	)		2,106

Regulated fuel for generation and purchased power		281		189			-		83		-			(6	)		547

Regulated cost of natural gas		-		-			53		-		-			-			53

OM&G		315		98			113		36		25			(9	)		578

Provincial, state and municipal taxes		84		12			26		1		1			-			124

Depreciation and amortization		176		74			52		21		1			-			324

Income from equity investments		-		10			4		1		-			-			15

Other income, net		19		11			3		3		(17	)		-			19

Interest expense, net (2)		79		45			37		5		94			-			260

Income tax expense (recovery)		51		(5	)		13		-		(53	)		-			6

NCI		-		-			-		1		-			-			1

Preferred stock dividends		-		-			-		-		19			-			19

Net income (loss) attributable to common shareholders	$	302	$	13		$	32	$	16	$	(135	)	$	-		$	228

For the nine months ended September 30, 2025
Operating revenues from external customers (1)	$	3,353	$	1,440		$	1,282	$	435	$	260		$	-		$	6,770

Inter-segment revenues (1)		8		-			13		-		23			(44	)		-

Total operating revenues		3,361		1,440			1,295		435		283			(44	)		6,770

Regulated fuel for generation and purchased power		772		671			-		223		-			(13	)		1,653

Regulated cost of natural gas		-		-			346		-		-			-			346

OM&G		821		327			350		110		90			(25	)		1,673

Provincial, state and municipal taxes		237		37			86		3		1			-			364

Depreciation and amortization		523		221			152		58		5			-			959

Income from equity investments		-		32			14		3		(1	)		-			48

Other income, net		66		25			9		5		24			6			135

Interest expense, net (2)		226		129			112		15		282			-			764

Impairment charges		-		-			-		-		75			-			75

Income tax expense (recovery)		122		(39	)		72		3		(42	)		-			116

NCI		-		-			-		1		-			-			1

Preferred stock dividends		-		-			-		-		56			-			56

Net income (loss) attributable to common shareholders	$	726	$	151		$	200	$	30	$	(161	)	$	-		$	946

As at September 30, 2025
Total assets	$	24,747	$	8,131		$	8,477	$	1,439	$	1,882		$	(873	)	$	43,803

Investments subject to significant influence	$	-	$	470		$	112	$	55	$	-		$	-		$	637

Goodwill	$	4,871	$	-		$	796	$	-	$	-		$	-		$	5,667

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

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


millions of dollars	Florida Electric Utility		Canadian Electric Utilities			Gas Utilities and Infrastructure		Other Electric Utilities		Other			Inter- Segment Eliminations			Total

For the three months ended September 30, 2024
Operating revenues from external customers (1)	$	985	$	399		$	297	$	150	$	(29	)	$	-		$	1,802

Inter-segment revenues (1)		3		-			3		-		(8	)		2			-

Total operating revenues		988		399			300		150		(37	)		2			1,802

Regulated fuel for generation and purchased power		224		185			-		78		-			(3	)		484

Regulated cost of natural gas		-		-			46		-		-			-			46

OM&G		196		87			103		39		12			(5	)		432

Provincial, state and municipal taxes		73		12			24		1		-			-			110

Depreciation and amortization		156		71			46		18		2			-			293

Income from equity investments		-		12			4		1		8			-			25

Other income (expenses), net		15		7			5		2		(5	)		(10	)		14

Interest expense, net (2)		66		41			38		5		91			-			241

Impairment charges		-		-			11		-		210			-			221

Income tax expense (recovery)		36		(4	)		11		-		(52	)		-			(9	)

NCI		-		-			-		1		-			-			1

Preferred stock dividends		-		-			-		-		18			-			18

Net income (loss) attributable to common shareholders	$	252	$	26		$	30	$	11	$	(315	)	$	-		$	4

For the nine months ended September 30, 2024
Operating revenues from external customers (1)	$	2,639	$	1,376		$	1,150	$	416	$	(144	)	$	-		$	5,437

Inter-segment revenues (1)		7		-			10		-		10			(27	)		-

Total operating revenues		2,646		1,376			1,160		416		(134	)		(27	)		5,437

Regulated fuel for generation and purchased power		641		639			-		217		-			(10	)		1,487

Regulated cost of natural gas		-		-			282		-		-			-			282

OM&G		587		299			333		106		105			(15	)		1,415

Provincial, state and municipal taxes		207		36			78		3		1			-			325

Depreciation and amortization		462		209			135		54		6			-			866

Income from equity investments		-		67			14		3		3			-			87

Other income, net		44		21			12		7		146			2			232

Interest expense, net (2)		197		126			115		16		271			-			725

Impairment charges		-		-			11		-		210			-			221

Income tax expense (recovery)		72		-			60		-		(92	)		-			40

NCI		-		-			-		1		-			-			1

Preferred stock dividends		-		-			-		-		54			-			54

Net income (loss) attributable to common shareholders	$	524	$	155		$	172	$	29	$	(540	)	$	-		$	340

As at December 31, 2024
Total assets	$	24,375	$	7,609		$	8,439	$	1,444	$	1,810		$		(726)	$	42,951

Investment subject to significant influence	$	-	$	475		$	124	$	55	$	-		$	-		$	654

Goodwill	$	5,035	$	-		$	823	$	-	$	-		$	-		$	5,858

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

5. REVENUE

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


	Electric						Gas		Other

millions of dollars	Florida Electric Utility		Canadian Electric Utilities		Other Electric Utilities		Gas Utilities and Infrastructure		Other		Inter- Segment Eliminations		Total

For the three months ended September 30, 2025
Regulated Revenue
Residential	$	787	$	197	$	59	$	116	$	-	$	-	$	1,159

Commercial		323		122		81		103		-		-		629

Industrial		71		68		7		26		-		(6)		166

Other electric		117		10		2		-		-		-		129

Regulatory deferrals		(35)		-		7		-		-		-		(28)

Other (1)		6		8		3		52		-		(3)		66

Finance income (2)(3)		-		-		-		16		-		-		16

Regulated revenue		1,269		405		159		313		-		(9)		2,137

Non-Regulated Revenue
Marketing and trading margin (4)		-		-		-		-		(3)		-		(3)

Other non-regulated operating revenue		-		-		-		6		9		(8)		7

Mark-to-market (3)		-		-		-		-		(37)		2		(35)

Non-regulated revenue		-		-		-		6		(31)		(6)		(31)

Total operating revenues	$	1,269	$	405	$	159	$	319	$	(31)	$	(15)	$	2,106


For the nine months ended September 30, 2025
Regulated Revenue
Residential	$	1,909	$	788	$	152	$	568	$	-	$	-	$	3,417

Commercial		858		390		231		395		-		-		1,874

Industrial		205		203		21		76		-		(14)		491

Other electric		384		32		6		-		-		-		422

Regulatory deferrals		(13)		-		16		-		-		-		3

Other (1)		18		27		9		190		-		(8)		236

Finance income (2)(3)		-		-		-		48		-		-		48

Regulated revenue		3,361		1,440		435		1,277		-		(22)		6,491

Non-Regulated Revenue
Marketing and trading margin (4)		-		-		-		-		98		-		98

Other non-regulated operating revenue		-		-		-		18		25		(21)		22

Mark-to-market (3)		-		-		-		-		160		(1)		159

Non-regulated revenue		-		-		-		18		283		(22)		279

Total operating revenues	$	3,361	$	1,440	$	435	$	1,295	$	283	$	(44)	$	6,770

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

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

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

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


	Electric						Gas		Other

millions of dollars	Florida Electric Utility		Canadian Electric Utilities		Other Electric Utilities		Gas Utilities and Infrastructure		Other		Inter- Segment Eliminations		Total

For the three months ended September 30, 2024
Regulated Revenue
Residential	$	643	$	191	$	56	$	107	$	-	$	-	$	997
Commercial		258		118		78		97		-		-		551
Industrial		56		70		9		24		-		(4)		155
Other electric		101		10		1		-		-		-		112
Regulatory deferrals		(76)		-		5		-		-		-		(71)
Other (1)		6		10		1		51		-		(3)		65
Finance income (2)(3)		-		-		-		16		-		-		16
Regulated revenue		988		399		150		295		-		(7)		1,825
Non-Regulated Revenue
Marketing and trading margin (4)		-		-		-		-		(7)		-		(7)
Other non-regulated operating revenue		-		-		-		5		7		(5)		7
Mark-to-market (3)		-		-		-		-		(37)		14		(23)
Non-regulated revenue		-		-		-		5		(37)		9		(23)
Total operating revenues	$	988	$	399	$	150	$	300	$	(37)	$	2	$	1,802

For the nine months ended September 30, 2024
Regulated Revenue
Residential	$	1,580	$	737	$	149	$	499	$	-	$	-	$	2,965
Commercial		710		371		224		361		-		-		1,666
Industrial		168		207		22		71		-		(11)		457
Other electric		318		31		4		-		-		-		353
Regulatory deferrals		(145)		-		13		-		-		-		(132)
Other (1)		15		30		4		167		-		(7)		209
Finance income (2)(3)		-		-		-		47		-		-		47
Regulated revenue		2,646		1,376		416		1,145		-		(18)		5,565
Non-Regulated Revenue
Marketing and trading margin (4)		-		-		-		-		42		-		42
Other non-regulated operating revenue		-		-		-		15		22		(16)		21
Mark-to-market (3)		-		-		-		-		(198)		7		(191)
Non-regulated revenue		-		-		-		15		(134)		(9)		(128)
Total operating revenues	$	2,646	$	1,376	$	416	$	1,160	$	(134)	$	(27)	$	5,437

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

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

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

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

Remaining Performance Obligations:

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

6. REGULATORY ASSETS AND LIABILITIES

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


As at millions of dollars	September 30 2025		December 31 2024

Regulatory assets (1)
Deferred income tax regulatory assets	$	1,287	$	1,227
TEC capital cost recovery for early retired assets		732		737
Pension and post-retirement medical plan		376		395
Storm cost recovery clauses		322		613
TEC capital cost recovery for retired Polk Unit 1 components		185		205
NSPI FAM		67		-
Cost recovery clauses		57		33
Deferrals related to derivative instruments		36		42
Environmental remediations		27		29
Stranded cost recovery		26		27
Other (2)		117		119
	$	3,232	$	3,427
Current	$	500	$	595
Long-term		2,732		2,832
Total regulatory assets	$	3,232	$	3,427

Regulatory liabilities (1)
Deferred income tax regulatory liabilities	$	775	$	828
Accumulated reserve – cost of removal		722		733
Cost recovery clauses		84		121
BLPC Self-insurance fund (“SIF”) (note 23)		31		32
Deferrals related to derivative instruments		22		44
NSPI FAM		-		56
Other (2)		67		66
	$	1,701	$	1,880
Current	$	218	$	262
Long-term		1,483		1,618
Total regulatory liabilities	$	1,701	$	1,880

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

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

Florida Electric Utility

Base Rates:

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

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

Storm Reserve:

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.

Canadian Electric Utilities

NSPI

Base Rates:

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

NSPML

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

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

Gas Utilities and Infrastructure

PGS

Base Rates:

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.

7. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME


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

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

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

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

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

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


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

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

8. OTHER INCOME, NET


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

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

9. INCOME TAXES

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


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

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

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

10. COMMON STOCK

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


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

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

11. EARNINGS PER SHARE

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


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

12. ACCUMULATED OTHER COMPREHENSIVE INCOME

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


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

For the nine months ended September 30, 2024
Balance, January 1, 2024	$	369	$	(24)	$	14	$	(2)	$	(52)	$	305
OCI before reclassifications		240		(33)		-		1		-		208
Amounts reclassified from AOCI		-		-		(2)		-		1		(1)
Net current period OCI		240		(33)		(2)		1		1		207
Balance, September 30, 2024	$	609	$	(57)	$	12	$	(1)	$	(51)	$	512

The reclassifications out of AOCI are as follows:


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

13. DERIVATIVE INSTRUMENTS

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

●

commodity price fluctuations related to the purchase and sale of commodities in the course of normal operations;

●

foreign exchange (“FX”) fluctuations on foreign currency denominated purchases and sales;

●

interest rate fluctuations on debt securities; and

●

share price fluctuations on stock-based compensation.

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

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

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

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

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

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

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


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

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

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

Cash Flow Hedges

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

Regulatory Deferral

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


millions of dollars	Commodity swaps and forwards		FX forwards		Commodity swaps and forwards		FX forwards
For the three months ended September 30				2025				2024
Unrealized (loss) gain in regulatory assets	$	(17)	$	4	$	(14)	$	(1)
Unrealized (loss) gain in regulatory liabilities		(7)		6		(6)		(1)
Realized gain in regulatory assets		(2)		-		(3)		-
Realized loss in regulatory liabilities		2		-		1		-
Realized loss (gain) loss in inventory (1)		3		(1)		3		(1)
Realized loss (gain) in regulated fuel for generation and purchased power (2)		7		(1)		16		(1)
Total change in derivative instruments	$	(14)	$	8	$	(3)	$	(4)

For the nine months ended September 30				2025				2024
Unrealized (loss) gain in regulatory assets	$	(32)	$	3	$	(1)	$	-
Unrealized gain (loss) in regulatory liabilities		10		(12)		6		13
Realized gain in regulatory assets		(5)		-		(7)		-
Realized loss in regulatory liabilities		5		-		1		-
Realized loss (gain) in inventory (1)		10		(5)		10		(5)
Realized loss (gain) in regulated fuel for generation and purchased power (2)		15		(3)		41		(5)
Total change in derivative instruments	$	3	$	(17)	$	50	$	3

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

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

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


millions	2025		2026-2027
Commodity swaps and forwards purchases:
Natural gas (MMBtu)		2		19
Power (MWh)		-		1
FX forwards:
FX contracts (millions of USD)	$	67	$	203
Weighted average rate		1.3422		1.3546
% of USD requirements		80%		40%

HFT Derivatives

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


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

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


millions	2025		2026		2027		2028		2029 and thereafter
Natural gas purchases (MMBtu)		156		391		137		56		74
Natural gas sales (MMBtu)		179		385		89		16		9
Power purchases (MWh)		1		1		-		-		-
Power sales (MWh)		1		1		1		-		-

Other Derivatives

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

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


millions of dollars	FX forwards		Equity derivatives		FX forwards		Equity derivatives
For the three months ended September 30			2025				2024
Unrealized gain in OM&G	$	-	$	11	$	-	$	22
Unrealized (loss) gain in other income, net		(14)		-		8		-
Realized loss in other income, net		(2)		-		(3)		-
Total (losses) gains in net income	$	(16)	$	11	$	5	$	22

For the nine months ended September 30				2025				2024
Unrealized gain in OM&G	$	-	$	36	$	-	$	8
Unrealized gain (loss) in other income, net		33		-		(8)		-
Realized loss in other income, net		(12)		-		(7)		-
Total gains (losses) in net income	$	21	$	36	$	(15)	$	8

Credit Risk

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

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

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

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

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

Cash Collateral

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


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

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

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

14. FV MEASUREMENTS

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

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

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

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

•

While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials.

•

The term of certain transactions extends beyond the period when quoted prices are available, and accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term.

•

The valuations of certain transactions were based on internal models, although quoted prices were utilized in the valuations.

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

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


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


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

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

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


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

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

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


	September 30, 2025
As at millions of dollars	FV				Significant Unobservable Input	Low		High		Weighted Average (1)
	Assets		Liabilities
HFT derivatives – Power swaps and physical contracts		5		4	Third-party pricing	$	27.50	$	144.40		$79.09
HFT derivatives – Natural gas swaps, futures, forwards and physical contracts		38		374	Third-party pricing		$0.69		$15.54		$8.64
Total	$	43	$	378
Net liability			$	335

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

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


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

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

15. RELATED PARTY TRANSACTIONS

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.

•

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.

16. RECEIVABLES AND OTHER CURRENT ASSETS


As at millions of dollars	September 30 2025		December 31 2024

Customer accounts receivable – billed		$ 963		$ 834

Customer accounts receivable – unbilled		370		342

Capitalized transportation capacity (1)		246		216

Cash collateral provided to others		142		198

Prepaid expenses		133		105

Income tax receivable		49		22

Allowance for credit losses		(13)		(12)

Other		215		106

Total receivables and other current assets		$ 2,105		$ 1,811

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

17. EMPLOYEE BENEFIT PLANS

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

Emera’s net periodic benefit cost included the following:


For the	Three months ended September 30				Nine months ended September 30
millions of dollars	2025		2024		2025		2024

DB pension plans
Service cost	$	9	$	9	$	27	$	26

Non-service cost:
Interest cost		29		27		86		82

Expected return on plan assets		(40)		(40)		(122)		(120)

Current year amortization of:
Actuarial losses		-		-		1		1

Regulatory asset		2		3		7		7

Total non-service costs		(9)		(10)		(28)		(30)

Total DB pension plans		-		(1)		(1)		(4)

Non-pension benefit plans
Service cost		-		1		2		2

Non-service cost:
Interest cost		3		3		9		9

Expected return on plan assets		(1)		(1)		(2)		(2)

Current year amortization of:
Regulatory asset		-		(1)		-		(3)

Past service costs		-		-		(1)		-

Total non-service costs		2		1		6		4

Total non-pension benefit plans		2		2		8		6

Total DB plans	$	2	$	1	$	7	$	2

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

18. SHORT-TERM DEBT

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

Canadian Electric Utilities

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.

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.

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 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.

19. LONG-TERM DEBT

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

Florida Electric Utility

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

Other

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

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.

20. COMMITMENTS AND CONTINGENCIES

A. Commitments

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


millions of dollars	2025		2026		2027		2028		2029		Thereafter		Total

Purchased power (1)	$	89	$	316	$	406	$	396	$	445	$	5,951	$	7,603

Transportation (2)(3)		241		725		578		466		407		3,122		5,539

Fuel, gas supply and storage (4)		227		660		130		45		40		99		1,201

Capital projects		342		149		40		5		2		-		538

Other		42		72		58		50		48		264		534

	$	941	$	1,922	$	1,212	$	962	$	942	$	9,436	$	15,415

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

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

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

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

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

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.

B. Legal Proceedings

Superfund and Former Manufactured Gas Plant Sites

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

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

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

Other Legal Proceedings

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

C. Principal Financial Risks and Uncertainties

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

D. Guarantees and Letters of Credit

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

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).

21. CUMULATIVE PREFERRED STOCK

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

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.

22. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


For the	Nine months ended September 30
millions of dollars	2025		2024

Changes in non-cash working capital:
Inventory	$	(84)	$	44

Receivables and other current assets		(230)		155

Accounts payable		(169)		(64)

Other current liabilities		101		85

Total non-cash working capital	$	(382)	$	220


Supplemental disclosure of non-cash activities:
Common share dividends reinvested	$	225	$	217

Increase in accrued capital expenditures	$	28	$	12

Accrued proceeds from disposal of investment subject to significant influence	$	-	$	25


Supplemental disclosure of operating activities:
Net change in short-term regulatory assets and liabilities	$	217	$	216

23. VARIABLE INTEREST ENTITIES

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

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

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

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

As at

September 30, 2025

December 31, 2024

millions of dollars

Total

assets

Maximum

exposure to

loss

Total
assets

Maximum

exposure to

loss

Unconsolidated VIEs in which Emera has variable interests

NSPML (equity accounted)

470

475

24. SUBSEQUENT EVENTS

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