EX-99.2

EX-99.2 3 d71872dex992.htm EX-99.2 EX-99.2

Exhibit 99.2

EMERA INCORPORATED

Unaudited Condensed Consolidated

Interim Financial Statements

March 31, 2025 and 2024

Emera Incorporated

Condensed Consolidated Statements of Income (Unaudited)


For the	Three months ended March 31
millions of dollars (except per share amounts)	2025		2024


Operating revenues
Regulated electric	$	1,660	$	1,415

Regulated gas		605		523

Non-regulated		411		80

Total operating revenues (note 5)		2,676		2,018


Operating expenses
Regulated fuel for generation and purchased power		575		512

Regulated cost of natural gas		220		180

Operating, maintenance and general expenses (“OM&G”)		518		500

Provincial, state and municipal taxes		119		106

Depreciation and amortization		319		283

Total operating expenses		1,751		1,581

Income from operations		925		437


Income from equity investments (note 7)		19		34

Other income, net		31		28

Interest expense, net		255		246

Income before provision for income taxes		720		253


Income tax expense (note 8)		119		28

Net income		601		225


Preferred stock dividends		18		18

Net income attributable to common shareholders	$	583	$	207


Weighted average shares of common stock outstanding (in millions) (note 10)
Basic		297.0		285.1

Diluted		297.3		285.2


Earnings per common share (note 10)
Basic	$	1.96	$	0.73

Diluted	$	1.96	$	0.73


Dividends per common share declared	$	0.7250	$	0.7175

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

Emera Incorporated

Condensed Consolidated Statements of Comprehensive Income (Unaudited)


For the	Three months ended March 31
millions of dollars	2025		2024

Net income	$	601	$	225

Other comprehensive income (loss) (“OCI”), net of tax
Foreign currency translation adjustment (1)		(12)		284

Unrealized gains (losses) on net investment hedges (2)		2		(39)

Cash flow hedges – reclassification adjustment for gains included in income		-		(1)

Unrealized (losses) gains on available-for-sale investment		-		1

Net change in unrecognized pension and post-retirement benefit obligation		(4)		1

OCI (3)	$	(14)	$	246

Comprehensive Income of Emera Incorporated	$	587	$	471

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

1) Net of tax expense of nil for the three months ended March 31, 2025 (2024 – $4 million expense).

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

3) Net of tax expense of nil for the three months ended March 31, 2025 (2024 – $4 million expense).

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited)


As at millions of dollars	March 31 2025		December 31 2024

Assets
Current assets
Cash and cash equivalents	$	308	$	196

Restricted cash		18		17

Inventory		756		781

Derivative instruments (notes 12 and 13)		178		115

Regulatory assets (note 6)		670		595

Receivables and other current assets (note 15)		1,907		1,811

Assets held for sale (note 3)		150		173

		3,987		3,688

Property, plant and equipment (“PP&E”), net of accumulated depreciation and amortization of $10,642 and $10,442, respectively		26,620		26,168

Other assets
Deferred income taxes (note 8)		314		392

Derivative instruments (notes 12 and 13)		72		51

Regulatory assets (note 6)		2,778		2,832

Net investment in direct finance and sales type leases		603		610

Investments subject to significant influence (note 7)		651		654

Goodwill		5,853		5,858

Other long-term assets (note 21)		560		538

Assets held for sale (note 3)		2,179		2,160

		13,010		13,095

Total assets	$	43,617	$	42,951

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

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited) – Continued


As at millions of dollars	March 31 2025		December 31 2024

Liabilities and Equity
Current liabilities
Short-term debt (note 17)	$	713	$	1,400

Current portion of long-term debt (note 18)		219		234

Accounts payable		1,974		1,992

Derivative instruments (notes 12 and 13)		332		526

Regulatory liabilities (note 6)		269		262

Other current liabilities		656		489

Liabilities associated with assets held for sale (note 3)		156		212

		4,319		5,115

Long-term liabilities
Long-term debt (note 18)		19,151		18,173

Deferred income taxes (note 8)		2,421		2,331

Derivative instruments (notes 12 and 13)		92		91

Regulatory liabilities (note 6)		1,532		1,618

Pension and post-retirement liabilities (note 16)		276		274

Other long-term liabilities (note 7)		935		910

Liabilities associated with assets held for sale (note 3)		1,148		1,148

		25,555		24,545

Equity
Common stock (note 9)		9,140		9,042

Cumulative preferred stock		1,422		1,422

Contributed surplus		84		84

Accumulated other comprehensive income (“AOCI’) (note 11)		1,247		1,261

Retained earnings		1,836		1,468

Total Emera Incorporated equity		13,729		13,277

Non-controlling interest in subsidiaries (“NCI”)		14		14

Total equity		13,743		13,291

Total liabilities and equity	$	43,617	$	42,951


Commitments and contingencies (note 19)		Nil		Nil

The accompanying notes are an integral part of these condensed consolidated 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	Three months ended March 31
millions of dollars	2025		2024

Operating activities
Net income	$	601	$	225

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		321		286

Income from equity investments, net of dividends		3		10

Allowance for funds used during construction (“AFUDC”) – equity		(18)		(9)

Deferred income taxes, net		137		19

Net change in pension and post-retirement liabilities		(9)		(14)

Nova Scotia Power Inc. (“NSPI”) Fuel adjustment mechanism (“FAM”)		(78)		(30)

Net change in fair value (“FV”) of derivative instruments		(254)		45

Net change in regulatory assets and liabilities		38		120

Net change in capitalized transportation capacity		(41)		(28)

Other operating activities, net		33		7

Changes in non-cash working capital (note 20)		(34)		(62)

Net cash provided by operating activities		699		569

Investing activities
Additions to PP&E		(724)		(601)

Other investing activities		16		(3)

Net cash used in investing activities		(708)		(604)

Financing activities
Change in short-term debt, net		(711)		(631)

Proceeds from long-term debt, net of issuance costs		905		664

Retirement of long-term debt		(7)		(39)

Net proceeds (repayments) under committed credit facilities		73		(162)

Issuance of common stock, net of issuance costs		20		31

Dividends on common stock		(139)		(133)

Dividends on preferred stock		(18)		(18)

Net cash provided by (used in) financing activities		123		(288)

Effect of exchange rate changes on cash, cash equivalents, restricted cash and cash associated with assets held for sale		-		11

Net increase (decrease) in cash, cash equivalents, restricted cash, and cash associated with assets held for sale		114		(312)

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	$	335	$	276

Cash, cash equivalents, restricted cash and cash associated with assets held for sale consists of:
Cash	$	303	$	254

Short-term investments		5		4

Restricted cash		18		18

Cash associated with assets held for sale		9		-

Total	$	335	$	276

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

Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)


millions of dollars	Common Stock		Preferred Stock		Contributed Surplus		AOCI		Retained Earnings		Non- Controlling Interest		Total Equity

For the three months ended March 31, 2025

Balance, December 31, 2024	$	9,042	$	1,422	$	84	$	1,261	$	1,468	$	14	$	13,291

Net income of Emera Incorporated		-		-		-		-		601		-		601

OCI, net of tax expense of nil		-		-		-		(14)		-		-		(14)

Dividends declared on preferred stock (1)		-		-		-		-		(18)		-		(18)

Dividends declared on common stock ($0.7250/share)		-		-		-		-		(215)		-		(215)

Issued under the at-the-market (“ATM”) program, net of after-tax issuance costs		10		-		-		-		-		-		10

Issued under the Dividend Reinvestment Program (“DRIP”), net of discounts		76		-		-		-		-		-		76

Senior management stock options exercised and Employee Common Share Purchase Plan (“ECSPP”)		12		-		-		-		-		-		12

Balance, March 31, 2025	$	9,140	$	1,422	$	84	$	1,247	$	1,836	$	14	$	13,743



For the three months ended March 31, 2024

Balance, December 31, 2023	$	8,462	$	1,422	$	82	$	305	$	1,803	$	14	$	12,088

Net income of Emera Incorporated		-		-		-		-		225		-		225

OCI, net of tax expense of $4 million		-		-		-		246		-		-		246

Dividends declared on preferred stock (2)		-		-		-		-		(18)		-		(18)

Dividends declared on common stock ($0.7175/share)		-		-		-		-		(204)		-		(204)

Issued under the ATM program, net of after-tax issuance costs		24		-		-		-		-		-		24

Issued under the DRIP, net of discount		70		-		-		-		-		-		70

Senior management stock options exercised and ECSPP		9		-		-		-		-		-		9

Balance, March 31, 2024	$	8,565	$	1,422	$	82	$	551	$	1,806	$	14	$	12,440

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

(1) Series A; $0.1364/share, Series B; $0.3630/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; $0.1364/share, Series B; $0.4408/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

Emera Incorporated

Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)

As at March 31, 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 March 31, 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 Q4 2025, 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 Canada”), 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 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., 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. There were no 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.

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.

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. The transaction is expected to close in Q4 2025, subject to certain approvals, including approval by the NMPRC. As a result of the pending sale, in Q3 2024 NMGC’s assets and liabilities were classified as held for sale and the carrying value of the assets and liabilities were adjusted to FV less cost to sell. There were no impairment or FV less costs to sell adjustments recorded in Q1 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 $44 million ($31 million USD) was recorded on these assets from August 5, 2024, the date they were classified as held for sale, through March 31, 2025. Of the $44 million ($31 million USD) recorded to date, $26 million ($19 million USD) was recorded in 2024.

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


As at millions of dollars	March 31 2025		December 31 2024
Cash and cash equivalents	$	9	$	8
Inventory		10		9
Derivative instruments		-		1
Regulatory assets		16		28
Receivables and other current assets		115		127
Current assets held for sale	$	150	$	173
PP&E		1,844		1,828
Regulatory assets		6		6
Goodwill		303		303
Other long-term assets		26		23
Long-term assets held for sale	$	2,179	$	2,160
Total assets held for sale	$	2,329	$	2,333

Short-term debt	$	20	$	46
Derivative instruments		-		1
Regulatory liabilities		18		10
Accounts payable and other current liabilities		118		155
Current liabilities associated with assets held for sale		156		212
Long-term debt		696		696
Deferred income taxes		171		167
Regulatory liabilities		273		274
Other long-term liabilities		8		11
Long-term liabilities associated with assets held for sale	$	1,148	$	1,148
Total liabilities associated with assets held for sale	$	1,304	$	1,360

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 March 31, 2025
Operating revenues from external customers (1)	$	930	$	599	$	611	$	131	$	405	$	-	$	2,676
Inter-segment revenues (1)		2		-		4		-		12		(18)		-
Total operating revenues		932		599		615		131		417		(18)		2,676
Regulated fuel for generation and purchased power		232		280		-		68		-		(5)		575
Regulated cost of natural gas		-		-		220		-		-		-		220
OM&G		212		120		123		36		35		(8)		518
Provincial, state and municipal taxes		72		12		34		1		-		-		119
Depreciation and amortization		175		73		51		18		2		-		319
Income from equity investments		-		11		6		1		1		-		19
Other income (expense), net		23		7		5		(1)		(8)		5		31
Interest expense, net (2)		74		41		37		5		98		-		255
Income tax expense (recovery)		26		(30)		41		3		79		-		119
Preferred stock dividends		-		-		-		-		18		-		18
Net income attributable to common shareholders	$	164	$	121	$	120	$	-	$	178	$	-	$	583
As at March 31, 2025 Total assets	$	24,735	$	7,826	$	8,641	$	1,459	$	1,832	$	(876)	$	43,617
Investments subject to significant influence	$	-	$	476	$	119	$	56	$	-	$	-	$	651
Goodwill	$	5,031	$	-	$	822	$	-	$	-	$	-	$	5,853
For the three months ended March 31, 2024
Operating revenues from external customers (1)	$	736	$	554	$	529	$	124	$	75	$	-	$	2,018
Inter-segment revenues (1)		2		-		3		-		15		(20)		-
Total operating revenues		738		554		532		124		90		(20)		2,018
Regulated fuel for generation and purchased power		189		260		-		65		-		(2)		512
Regulated cost of natural gas		-		-		180		-		-		-		180
OM&G		187		117		116		30		53		(3)		500
Provincial, state and municipal taxes		63		12		29		1		1		-		106
Depreciation and amortization		151		69		44		17		2		-		283
Income from equity investments		-		30		5		1		(2)		-		34
Other income (expenses), net		15		7		2		4		(15)		15		28
Interest expense, net (2)		67		43		39		6		91		-		246
Income tax expense (recovery)		11		3		33		-		(19)		-		28
Preferred stock dividends		-		-		-		-		18		-		18
Net income (loss) attributable to common shareholders	$	85	$	87	$	98	$	10	$	(73)	$	-	$	207
As at December 31, 2024 Total assets	$	24,375	$	7,609	$	8,439	$	1,444	$	1,810	$	(726)	$	42,951
Investments subject to significant influence	$	-	$	475	$	124	$	55	$	-	$	-	$	654
Goodwill	$	5,035	$	-	$	823	$	-	$	-	$	-	$	5,858

(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 and agreed to 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 March 31, 2025, between the Gas Utilities and Infrastructure and Other segments (2024 – $7 million).

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 March 31, 2025
Regulated Revenue:
Residential	$	483	$	361	$	42	$	314	$	-	$	-	$	1,200
Commercial		247		148		75		178		-		-		648
Industrial		66		68		6		26		-		(4)		162
Other electric		116		12		2		-		-		-		130
Regulatory deferrals		14		-		3		-		-		-		17
Other (1)		6		10		3		74		-		(2)		91
Finance income (2)(3)		-		-		-		17		-		-		17
Regulated revenue		932		599		131		609		-		(6)		2,265
Non-Regulated Revenue:
Marketing and trading margin (4)		-		-		-		-		120		-		120
Other non-regulated operating revenues		-		-		-		6		9		(6)		9
Mark-to-market (3)		-		-		-		-		288		(6)		282
Non-regulated revenue		-		-		-		6		417		(12)		411
Total operating revenues	$	932	$	599	$	131	$	615	$	417	$	(18)	$	2,676

For the three months ended March 31, 2024
Regulated Revenue:
Residential	$	409	$	329	$	44	$	268	$	-	$	-	$	1,050
Commercial		209		138		68		160		-		-		575
Industrial		54		67		7		24		-		(3)		149
Other electric		92		12		1		-		-		-		105
Regulatory deferrals		(31)		-		3		-		-		-		(28)
Other (1)		5		8		1		60		-		(2)		72
Finance income (2)(3)		-		-		-		15		-		-		15
Regulated revenue		738		554		124		527		-		(5)		1,938
Non-Regulated:
Marketing and trading margin (4)		-		-		-		-		80		-		80
Other non-regulated operating revenues		-		-		-		5		9		(6)		8
Mark-to-market (3)		-		-		-		-		1		(9)		(8)
Non-regulated revenue		-		-		-		5		90		(15)		80
Total operating revenues	$	738	$	554	$	124	$	532	$	90	$	(20)	$	2,018

(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 Canada.

(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 March 31, 2025, the aggregate amount of the transaction price allocated to remaining performance obligations was $480 million (2024 – $477 million), including $1 million related to NMGC. This amount includes $132 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	March 31 2025 (1)		December 31 2024 (1)
Regulatory assets
Deferred income tax regulatory assets	$	1,276	$	1,227
TEC capital cost recovery for early retired assets		740		737
Storm cost recovery clauses		569		613
Pension and post-retirement medical plan		392		395
TEC capital cost recovery for retired Polk Unit 1 components		200		205
Cost recovery clauses		45		33
Deferrals related to derivative instruments		36		42
Environmental remediations		28		29
Stranded cost recovery		27		27
NSPI FAM		22		-
Other (2)		113		119
	$	3,448	$	3,427
Current	$	670	$	595
Long-term		2,778		2,832
Total regulatory assets	$	3,448	$	3,427

Regulatory liabilities
Deferred income tax regulatory liabilities	$	821	$	828
Accumulated reserve – COR		723		733
Cost recovery clauses		111		121
NSPI FAM		-		56
Deferrals related to derivative instruments		50		44
BLPC Self-insurance fund (“SIF”) (note 21)		32		32
Other (2)		64		66
	$	1,801	$	1,880
Current	$	269	$	262
Long-term		1,532		1,618
Total regulatory liabilities	$	1,801	$	1,880

(1) On August 5, 2024, Emera announced an agreement to sell NMGC. As at March 31, 2025, NMGC’s assets and liabilities were classified as held for sale 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 February 3, 2025, the Florida Public Service Commission (“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. 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. As of May 8, 2025, 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 beginning in March 2025. The amount of cost-recovery is subject to a true-up mechanism with the FPSC.

Canadian Electric Utilities

NSPML

On November 29, 2024, NSPML received approval from the Nova Scotia Energy Board (“NSEB”), formally Nova Scotia Utility and Review Board, 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 Q1 2025.

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 2026. PGS requested a $104 million USD increase in annual base rates and an additional adjustment of $27 million USD for 2027. The request for 2026 includes $7 million USD from the cast iron and bare steel replacement rider. The proposed rates include recovery of investments in the gas system to meet the needs of a growing customer base and to improve reliability, resiliency, and efficiency.

7. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME


	March 31		Carrying Value as at December 31		Equity Income for the three months ended March 31				Percentage of Ownership
millions of dollars	2025		2024		2025		2024		2025
NSPML	$	476	$	475	$	11	$	13		100.0
M&NP (1)		119		124		6		5		12.9
Lucelec (1)		56		55		1		1		19.5
LIL (2)		-		-		-		17		-
Bear Swamp (3)		-		-		1		(2)		50.0
WTI (4)		-		-		-		-		50.0
	$	651	$	654	$	19	$	34

(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 Labrador Island Link Partnership (“LIL”).

(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 $91 million (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 March 31, 2025, NSPI’s investment was nominal.

Emera accounts for its variable interest investment in NSPML as an equity investment (note 21). NSPML’s consolidated summarized balance sheet is as follows:


As at millions of dollars	March 31 2025		December 31 2024
Current assets	$	66	$	37
PP&E		1,412		1,425
Regulatory assets		778		778
Non-current assets		28		27
Total assets	$	2,284	$	2,267
Current liabilities	$	82	$	55
Long-term debt (1)		1,553		1,570
Non-current liabilities		173		167
Equity		476		475
Total liabilities and equity	$	2,284	$	2,267
(1) The debt has been guaranteed by the Government of Canada. 8. 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:
For the	Three months ended March 31
millions of dollars	2025		2024
Income before provision for income taxes	$	720	$	253
Statutory income tax rate		29.0%		29.0%
Income taxes, at statutory income tax rate		209		73
Tax credits		(40)		(8)
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities		(28)		(21)
Amortization of deferred income tax regulatory liabilities		(9)		(6)
Foreign tax rate variance		(9)		(7)
Tax effect of equity earnings		(4)		(4)
Other		-		1
Income tax expense	$	119	$	28
Effective income tax rate		17%		11%

9. 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
Issuance of common stock under ATM program (1)		0.19		10
Issued under the DRIP, net of discounts		1.39		76
Senior management stock options exercised and ECSPP		0.22		12
Balance, March 31, 2025		297.74	$	9,140

(1) For the three months ended March 31, 2025, 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 March 31, 2025, an aggregate gross sales limit of $326 million remained available for issuance under the ATM program.

10. EARNINGS PER SHARE

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


For the	Three months ended March 31
millions of dollars (except per share amounts)	2025		2024
Numerator
Net income attributable to common shareholders	$	583.4	$	207.2
Diluted numerator		583.4		207.2
Denominator
Weighted average shares of common stock outstanding – basic	$	297.0	$	285.1
Stock-based compensation		0.3		0.1
Weighted average shares of common stock outstanding – diluted	$	297.3	$	285.2
Earnings per common share
Basic	$	1.96	$	0.73
Diluted	$	1.96	$	0.73

11. 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 three months ended March 31, 2025
Balance, January 1, 2025	$	1,396	$	(163)	$	12	$	-	$	16	$	1,261
OCI before reclassifications		(12)		2		-		-		-		(10)
Amounts reclassified from AOCI		-		-		-		-		(4)		(4)
Net current period OCI		(12)		2		-		-		(4)		(14)
Balance, March 31, 2025	$	1,384	$	(161)	$	12	$	-	$	12	$	1,247

For the three months ended March 31, 2024
Balance, January 1, 2024	$	369	$	(24)	$	14	$	(2)	$	(52)	$	305
OCI before reclassifications		284		(39)		-		1		-		246
Amounts reclassified from AOCI		-		-		(1)		-		1		-
Net current period OCI		284		(39)		(1)		1		1		246
Balance, March 31, 2024	$	653	$	(63)	$	13	$	(1)	$	(51)	$	551

The reclassifications out of AOCI are as follows:

For the

Three months ended March 31

millions of dollars

2025

2024

Affected line item in the Condensed

Consolidated Financial Statements

Amounts reclassified from AOCI

Gains on derivatives recognized as cash flow hedges

Interest rate hedge

Interest expense, net

(1)

Net change in unrecognized pension and post-retirement benefit costs

Amounts reclassified into obligations

Pension and post-retirement benefits

(4)

Total reclassifications out of AOCI for the period

(4)

12. 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 millions of dollars	March 31 2025			December 31 2024			March 31 2025			December 31 2024
Regulatory deferral:
Commodity swaps and forwards	$	34		$	25		$	38		$	44
FX forwards		19			27			-			3
		53			52			38			47
HFT derivatives:
Power swaps and physical contracts		23			34			20			30
Natural gas swaps, futures, forwards, physical contracts		318			236			500			660
		341			270			520			690
Other derivatives:
Equity derivatives		19			-			-			2
FX forwards		-			-			29			34
		19			-			29			36
Total gross derivatives		413			322			587			773
Impact of master netting agreements:
Regulatory deferral		(3	)		(7	)		(3	)		(7	)
HFT derivatives		(160	)		(148	)		(160	)		(148	)
Total impact of master netting agreements		(163	)		(155	)		(163	)		(155	)
Less: Derivatives classified as held for sale (1)		-			(1	)		-			(1	)
Total derivatives	$	250		$	166		$	424		$	617
Current (2)		178			115			332			526
Long-term (2)		72			51			92			91
Total derivatives	$	250		$	166		$	424		$	617

(1) On August 5, 2024, Emera announced an agreement to sell NMGC. As at March 31, 2025, NMGC’s assets and liabilities were classified as held for sale. 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 March 31, 2025, the unrealized gain in AOCI was $12 million, after-tax (December 31, 2024 – $12 million, after-tax). For the three months ended March 31, 2025, unrealized gains of nil (2024 – $1 million) 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 March 31					2025						2024
Unrealized gain (loss) in regulatory assets	$	(10	)	$	5		$	8		$	-
Unrealized gain (loss) in regulatory liabilities		20			(4	)		15			11
Realized gain in regulatory assets		(1	)		-			(1	)		-
Realized (gain) loss in regulatory liabilities		2			-			(1	)		-
Realized (gain) loss in inventory (1)		3			(4	)		4			(2	)
Realized (gain) loss in regulated fuel for generation and purchased power (2)		1			-			7			(2	)
Other		-			(2	)		-			-
Total change in derivative instruments	$	15		$	(5	)	$	32		$	7

(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 March 31, 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)		10		11
Power (MWh)		1		1
Coal (metric tonnes)		1		-
FX forwards:
FX contracts (millions of USD)		$ 211		$ 89
Weighted average rate		1.3655		1.3416
% of USD requirements		66%		13%

HFT Derivatives

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


For the	Three months ended March 31
millions of dollars	2025		2024
Power swaps and physical contracts in non-regulated operating revenues	$	-	$	10
Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues		466		150
Total gains in net income	$	466	$	160

As at March 31, 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)		364		254		106		51		73
Natural gas sales (MMBtu)		401		180		50		15		9
Power purchases (MWh)		1		-		-		-		-
Power sales (MWh)		1		1		1		-		-

Other Derivatives

As at March 31, 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 $618 million USD and expire in 2025 through 2027.


For the			Three months ended March 31
millions of dollars			2025				2024
	FX forwards		Equity derivatives		FX forwards		Equity derivatives
Unrealized gain (loss) in OM&G	$	-	$	20	$	-	$	(8)
Unrealized gain (loss) in other income, net		4		-		(2)		-
Realized loss in other income, net		(8)		-		(1)		-
Total gains (losses) in net income	$	(4)	$	20	$	(3)	$	(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 March 31, 2025, the Company had $139 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 $127 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	March 31 2025		December 31 2024
Cash collateral provided to others	$	138	$	198
Cash collateral received from others	$	6	$	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 March 31, 2025, the total FV of derivatives in a liability position was $424 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.

13. FV MEASUREMENTS

The Company is required to determine the FV of all derivatives except those which qualify for the NPNS exemption (see note 12), 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	March 31, 2025
millions of dollars	Level 1		Level 2		Level 3		Total
Assets
Regulatory deferral:
Commodity swaps and forwards	$	30	$	1	$	-	$	31
FX forwards		-		19		-		19
		30		20		-		50
HFT derivatives:
Power swaps and physical contracts		2		8		5		15
Natural gas swaps, futures, forwards, physical contracts and related transportation		21		111		34		166
		23		119		39		181
Other derivatives:
Equity derivatives		19		-		-		19
Total assets		72		139		39		250
Liabilities
Regulatory deferral:
Commodity swaps and forwards		6		29		-		35
HFT derivatives:
Power swaps and physical contracts		1		7		4		12
Natural gas swaps, futures, forwards and physical contracts		17		73		258		348
		18		80		262		360
Other derivatives:
FX forwards		-		29		-		29
Total liabilities		24		138		262		424
Net assets (liabilities)	$	48	$	1	$	(223)	$	(174)


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 at March 31, 2025, NMGC’s assets and liabilities were classified as held for sale. 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

	March 31, 2025
	HFT Derivatives
millions of dollars	Power		Natural gas		Total
Assets
Balance, beginning of period	$	5	$	27	$	32
Total realized and unrealized gains or losses included in non-regulated operating revenues		-		7		7
Balance, March 31, 2025	$	5	$	34	$	39
Liabilities
Balance, beginning of period	$	4	$	437	$	441
Total realized and unrealized gains or losses included in non-regulated operating revenues		-		(179)		(179)
Balance, March 31, 2025	$	4	$	258	$	262

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:


	March 31, 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	$	140.25		$75.36
HFT derivatives – Natural gas swaps, futures, forwards and physical contracts		34		258	Third-party pricing		$2.68		$15.88		$6.91
Total	$	39	$	262
Net liability			$	223

(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
March 31, 2025	$	19,370	$	18,466	$	-	$	18,223	$	243	$	18,466
December 31, 2024	$	18,407	$	16,621	$	-	$	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 gain of $2 million was recorded in AOCI for the three months ended March 31, 2025 (2024 – $39 million loss after-tax).

14. 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 March 31, 2025 (2024 – $42 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 $8 million for the three months ended March 31, 2025 (2024 – $4 million).

●

On March 4, 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 Statement of Income.

As at March 31, 2025, Emera and its associated companies had $37 million due to related parties (December 31, 2024 – $24 million) recorded in “Other Current Liabilities” on the Condensed Consolidated Balance Sheets.

15. RECEIVABLES AND OTHER CURRENT ASSETS


As at	March 31		December 31
millions of dollars	2025		2024
Customer accounts receivable – billed	$	884	$	834
Customer accounts receivable – unbilled		352		342
Capitalized transportation capacity (1)		252		216
Cash collateral provided to others		138		198
Prepaid expenses		105		105
Income tax receivable		60		22
Allowance for credit losses		(12)		(12)
Other		128		106
Total receivables and other current assets	$	1,907	$	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.

16. 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 March 31


millions of dollars	2025		2024
DB pension plans
Service cost	$	9	$	8
Non-service cost:
Interest cost		29		27
Expected return on plan assets		(41)		(39)
Current year amortization of regulatory asset		3		2
Total non-service costs		(9)		(10)
Total DB pension plans		-		(2)
Non-pension benefits plan
Service cost		1		1
Non-service cost:
Interest cost		3		3
Expected return on plan assets		(1)		(1)
Current year amortization of regulatory asset		-		(1)
Total non-service costs		2		1
Total non-pension benefits plans		3		2
Total DB pension and non-pension plans	$	3	$	-

Emera’s contributions related to these DB pension plans for the three months ended March 31, 2025 were $13 million (2024 – $12 million). Annual employer cash contributions to the DB pension plans are estimated to be $41 million for 2025. Emera’s cash contributions related to these DC pension plans for the three months ended March 31, 2025 were $13 million (2024 – $12 million).

17. 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.

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.

18. 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. Proceeds from this issuance were used for the repayment of a portion of TEC’s outstanding commercial paper.

19. COMMITMENTS AND CONTINGENCIES

A.	Commitments

As at March 31, 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
Transportation (1)(2)	$	652	$	622	$	568	$	475	$	425	$	3,589	$	6,331
Purchased power (3)		320		287		379		378		379		4,544		6,287
Fuel, gas supply and storage (4)		697		180		82		37		35		88		1,119
Capital projects		528		278		22		4		1		-		833
Other		118		87		71		47		45		260		628
	$	2,315	$	1,454	$	1,122	$	941	$	885	$	8,481	$	15,198

As detailed below, commitments at March 31, 2025 include those related to NMGC. On completion of the sale of NMGC, all the remaining future commitments will be transferred to the buyer. For further details on the pending transaction, refer to note 3.

(1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $132 million related to a gas transportation contract between PGS and SeaCoast through 2040.

(2) Includes $71 million related to NMGC (2025: $16 million, 2026: $24 million, 2027: $16 million, 2028: $12 million, 2029: $3 million).

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

(4) Includes $108 million related to NMGC (2025: $38 million, 2026: $54 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 March 31, 2025, the aggregate financial liability of the Florida utilities is estimated to be $17 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 12 and note 13. There have been no material changes to the principal financial risks as of March 31, 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.

20. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


For the	Three months ended March 31
millions of dollars			2025		2024
Changes in non-cash working capital:

Inventory		$	25	$	55
Receivables and other current assets			(40)		50
Accounts payable			(151)		(250)
Other current liabilities			132		83
Total non-cash working capital		$	(34)	$	(62)

Supplemental disclosure of non-cash activities:
Common share dividends reinvested		$	76	$	70
(Decrease) increase in accrued capital expenditures		$	(83)	$	30

Supplemental disclosure of operating activities:
Net change in short-term regulatory assets and liabilities		$	93	$	108

21. 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

March 31, 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)

476

475

22. 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 May 8, 2025, the date the unaudited condensed consolidated interim financial statements were issued.

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 have been taken to contain and isolate the affected servers and prevent further intrusion and to notify law enforcement in Canada and the United States (“US”). There remains no disruption to any of our Canadian physical operations, including at NSPI’s generation, transmission and distribution facilities, the Maritime Link, or the Brunswick Pipeline. There has been no impact to Emera’s US or Caribbean utilities’ operations. The investigation and assessment of the financial and other impacts of the Cybersecurity Incident is ongoing. At this time, the Cybersecurity Incident is not expected to have a material impact on the Company’s financial condition or results of operations.