Exhibit 99.1

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Management’s Discussion & Analysis

As at August 8, 2025

Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its consolidated subsidiaries and investments (collectively referred to as “Emera” or the “Company”) during the second quarter of, and year-to-date 2025 relative to the same periods in 2024; and its financial position as at June 30, 2025 relative to December 31, 2024. The Company’s activities are carried out through five reportable segments: Florida Electric Utility, Canadian Electric Utilities, Gas Utilities and Infrastructure, Other Electric Utilities, and Other.

This MD&A should be read in conjunction with the Emera unaudited condensed consolidated interim financial statements and supporting notes as at and for the three and six months ended June 30, 2025; and the Emera annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2024. Emera follows United States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”). Additional information related to Emera, including the Company’s Annual Information Form, can be found on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov.

The accounting policies used by Emera’s rate-regulated entities may differ from those used by Emera’s non-rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities, revenues and expenses. At June 30, 2025, Emera’s rate-regulated subsidiaries and investments include:


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

All amounts are in Canadian dollars (“CAD”), except for the Florida Electric Utility, Gas Utilities and Infrastructure, and Other Electric Utilities sections of the MD&A, which are reported in United States dollars (“USD”) unless otherwise stated.

TABLE OF CONTENTS


Forward-looking Information			2
Introduction and Strategic Overview			3
Non-GAAP Financial Measures and Ratios			4
Consolidated Financial Review			6
Significant Items Affecting Earnings			6
Consolidated Financial Highlights			7
Consolidated Income Statement Highlights			8
Business Overview and Outlook			10
Florida Electric Utility			10
Canadian Electric Utilities			11
Gas Utilities and Infrastructure			12
Other Electric Utilities			12
Other			13
Consolidated Balance Sheet Highlights			14
Other Developments			15
Financial Highlights			16
Florida Electric Utility			16
Canadian Electric Utilities			17


Gas Utilities and Infrastructure			18
Other Electric Utilities			19
Other			20
Liquidity and Capital Resources			22
Consolidated Cash Flow Highlights			22
Contractual Obligations			24
Debt Management			25
Credit Ratings			25
Guarantees and Letters of Credit			26
Outstanding Stock Data			26
Transactions with Related Parties			27
Risk Management including Financial Instruments			28
Disclosure and Internal Controls			29
Critical Accounting Estimates			29
Changes in Accounting Policies and Practices			29
Future Accounting Pronouncements			29
Summary of Quarterly Results			30

FORWARD-LOOKING INFORMATION

This MD&A contains “forward-looking information” (“FLI”) and statements which reflect the current view with respect to the Company’s expectations regarding future growth, results of operations, performance, the expected timing and outcome of the pending sale of NMGC, the scope of the Cybersecurity Incident and its expected impact on the Company’s financial position and results of operations, IT systems restoration, insurance recoveries, and business continuity processes as well as other matters relating to the Cybersecurity Incident, including business prospects and opportunities, and may not be appropriate for other purposes within the meaning of applicable Canadian securities laws. All such information and statements are made pursuant to safe harbour provisions contained in applicable securities legislation. The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecast”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “targets”, “will”, “would” and similar expressions are often intended to identify FLI, although not all FLI contains these identifying words. The FLI reflects management’s current beliefs and is based on information currently available to Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the time at which, such events, performance or results will be achieved.

FLI is based on reasonable assumptions and is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the FLI. Factors that could cause results or events to differ from current expectations include, without limitation: regulatory and political risk; change in law risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; liquidity and capital markets risk; changes in credit ratings; future dividend growth, rate base growth, and adjusted earnings per common share (“EPS”) growth; timing and costs associated with certain capital investments; expected impacts on Emera of challenges in the global economy; potential impacts of trade disputes and tariffs; estimated energy consumption rates; maintenance of adequate insurance coverage and receipt of proceeds; changes in customer energy usage patterns; developments in technology that could reduce demand for electricity; climate change risk; weather risk, including higher frequency and severity of weather events; risk of wildfires; unanticipated maintenance and other expenditures; system operating and maintenance risk; derivative financial instruments and hedging; interest rate risk; inflation risk; counterparty risk; disruption of fuel supply; country risks; supply chain risk; environmental risks; foreign exchange (“FX”); regulatory and government decisions, including changes to environmental legislation, financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of service area; risks and costs associated with failure of information technology (“IT”) infrastructure and cybersecurity incidents including IT systems restoration and business continuity processes; uncertainties associated with infectious diseases, pandemics and similar public health threats; market energy sales prices; labour relations; and availability of labour and management resources.

Readers are cautioned not to place undue reliance on FLI, as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the FLI. All FLI in this MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, Emera undertakes no obligation to revise or update any FLI as a result of new information, future events or otherwise.

INTRODUCTION AND STRATEGIC OVERVIEW

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

Emera’s business strategy is centred on continued investment in its regulated utilities, combined with a focus on operational excellence and efficiency, to safely and reliably deliver energy to its 2.6 million customers. Effective execution of these priorities supports predictable and growing earnings, cash flow and dividends for shareholders.

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

Emera’s capital investment plan is forecasted to be approximately $20 billion from 2025 through 2029 and is focused on delivering value for customers through prudent investments in reliability and system resiliency, infrastructure modernization, expansion to address customer growth, integration of renewables, and technological innovations to deliver better customer experiences. It is anticipated that approximately 80 per cent of this capital investment will be made in Emera’s Florida utilities, necessitated by customer growth and system requirements at both TEC and PGS.


As at millions of dollars	2025		2026		2027		2028		2029		Total
Capital investment plan	$	3,420	$	3,990	$	4,050	$	4,380	$	4,590	$	20,430
Average consolidated rate base
US operations	$	21,520	$	23,340	$	25,140	$	27,050	$	29,400
Canadian operations		7,630		8,000		8,370		8,590		8,870
Total	$	29,150	$	31,340	$	33,510	$	35,640	$	38,270

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

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

Emera has increased dividends per common share paid for 18 consecutive years and has provided forward annual dividend growth guidance of one to two per cent. Emera anticipates adjusted EPS average growth of five to seven per cent through 2027 which will support reduction in the ratio of dividend payout to adjusted net income. For further information on the non-GAAP ratios “Adjusted EPS” and “Dividend Payout Ratio of Adjusted Net Income”, refer to the “Non-GAAP Financial Measures and Ratios” section.

NON-GAAP FINANCIAL MEASURES AND RATIOS

Emera uses financial measures and ratios that do not have standardized meaning under USGAAP and are calculated by adjusting certain GAAP measures for specific items. They may not be comparable to similar measures presented by other entities. These measures and ratios are discussed and reconciled below.

Adjusted Net Income, Adjusted EPS – Basic and Dividend Payout Ratio of Adjusted Net Income

Emera calculates an adjusted net income attributable to common shareholders (“adjusted net income”) measure by excluding the items below from net income attributable to common shareholders. Management believes excluding these items better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the business.

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

Adjusted EPS – basic and dividend payout ratio of adjusted net income are non-GAAP ratios which are calculated using adjusted net income, as described above. For further details on dividend payout ratio of adjusted net income, see the “Dividend Payout Ratio” section in the Company’s 2024 annual MD&A.

Adjusted Item Impacting All Periods

Mark-to-market (“MTM”) Adjustments:

Management believes excluding from net income the effect of MTM valuations and changes thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows, and therefore excludes MTM adjustments for evaluation of performance and incentive compensation. The MTM adjustments are related to the following:

●

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

●

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

●

equity securities held in BLPC and Emera Energy; and

●

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

Adjusting Item Impacting 2025:

Charges Related to the Pending Sale of NMGC:

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

Adjusting Item Impacting 2024:

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

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

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


	Three months ended				Six months ended
For the	June 30				June 30
millions of dollars (except per share amounts)	2025		2024		2025		2024
Net income attributable to common shareholders	$	135	$	129	$	718	$	336
Less:
Charges related to the pending sale of NMGC, after-tax (1)(2)		(72)		-		(72)		-
Gain on sale of LIL, after-tax (3)		-		107		-		107
MTM (loss) gain, after-tax (4)		(29)		(129)		175		(138)
Adjusted net income	$	236	$	151	$	615	$	367
EPS – basic	$	0.45	$	0.45	$	2.41	$	1.17
Adjusted EPS – basic	$	0.79	$	0.53	$	2.07	$	1.28

(1) Represents a $71 million non-cash impairment charge, after-tax, and $1 million in transaction costs, after-tax for the three and six months ended June 30, 2025.

(2) Net of income tax recovery of $5 million for the three and six months ended June 30, 2025.

(3) Net of income tax expense of $75 million for the three and six months ended June 30, 2024.

(4) Net of income tax recovery of $13 million for the three months ended June 30, 2025 (2024 – $52 million recovery) and $71 million income tax expense for the six months ended June 30, 2025 (2024 – $56 million recovery).

EBITDA and Adjusted EBITDA

Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) and adjusted EBITDA are non-GAAP financial measures used by Emera. These financial measures are used by numerous investors and lenders to better understand cash flows and credit quality. EBITDA is useful to assess Emera’s operating performance and indicates the Company’s ability to service or incur debt, invest in capital, and finance working capital requirements. Adjusted EBITDA represents EBITDA absent the income effect of MTM adjustments, charges related to the pending sale of NMGC, and the 2024 gain on the sale of LIL.

Reconciliation of Net Income to EBITDA and Adjusted EBITDA:


	Three months ended				Six months ended
For the	June 30				June 30
millions of dollars	2025		2024		2025		2024
Net income (1)	$	154	$	147	$	755	$	372
Interest expense, net		249		238		504		484
Income tax (recovery) expense		(9)		21		110		49
Depreciation and amortization		316		290		635		573
EBITDA	$	710	$	696	$	2,004	$	1,478
Less:
Charges related to the pending sale of NMGC, excluding income tax		(77)		-		(77)		-
Gain on sale of LIL, excluding income tax		-		182		-		182
MTM (loss) gain, excluding income tax		(42)		(181)		246		(194)
Adjusted EBITDA	$	829	$	695	$	1,835	$	1,490

(1) Net income is before Non-controlling interest in subsidiaries and Preferred stock dividends.

CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Earnings

Charges Related to the Pending Sale of NMGC

In Q2 2025, Emera recognized a non-cash impairment charge of $75 million ($71 million after-tax, or $0.24 per common share) related to the remeasurement of the NMGC disposal group to fair value (“FV”) less costs to sell. This was recorded in “Impairment Charge” on the Condensed Consolidated Statements of Income and included in the Other segment. For further details on the pending sale of NMGC, refer to the “Other Developments” section. For further details on the non-cash impairment charge, refer to note 3 in the condensed consolidated interim financial statements.

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

MTM loss, after-tax, decreased $100 million to $29 million in Q2 2025, compared to $129 million in Q2 2024. Year-to-date, the 2024 MTM loss, after-tax, of $138 million, decreased $313 million to a $175 million MTM gain, after-tax, for the same period in 2025. These changes were primarily due to lower amortization of gas transportation assets at Emera Energy Services (“EES”), and a gain on Corporate FX hedges compared to a loss in prior year. Year-over-year change was also driven by changes in existing positions at EES.

2024

Gain on Sale of LIL

On June 4, 2024, Emera completed the sale of its LIL equity interest. A gain on sale of $182 million after transaction costs ($107 million, after tax and transaction costs, or $0.37 per common share), was recognized in “Other Income, net” on the Condensed Consolidated Statements of Income and included in the Other segment. For further details, refer to note 3 in the condensed consolidated interim financial statements.

Consolidated Financial Highlights


For the	Three months ended				Six months ended
millions of dollars	June 30				June 30
Adjusted Net Income	2025		2024		2025		2024
Florida Electric Utility	$	260	$	187	$	424	$	272
Canadian Electric Utilities		17		42		138		129
Gas Utilities and Infrastructure		48		44		168		142
Other Electric Utilities		12		8		12		17
Other		(101)		(130)		(127)		(193)
Adjusted net income	$	236	$	151	$	615	$	367
Charges related to the pending sale of NMGC, after-tax		(72)		-		(72)		-
Gain on sale of LIL, after-tax		-		107		-		107
MTM (loss) gain, after-tax		(29)		(129)		175		(138)
Net income attributable to common shareholders	$	135	$	129	$	718	$	336

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


For the	Three months ended		Six months ended
millions of dollars	June 30		June 30
Adjusted net income – 2024	$	151	$	367
Operating Unit Performance
Increased earnings at TEC due to higher revenue from new base rates, favourable weather, and customer growth, partially offset by increased income tax expense and higher depreciation. Year-over-year increase also due to the impact of a weaker CAD		73		152
Increased earnings at EES quarter-over-quarter due to lower transport costs and favourable hedge settlements related to EES’ storage positions. Year-over-year increased due to favourable weather and resulting market conditions (higher natural gas prices and increased volatility)		10		34
Increased earnings at NMGC due to higher revenue from new base rates. Year-over-year increase also due to the impact of a weaker CAD		7		26
Decreased income from equity investments due to the sale of LIL in Q2 2024		(11)		(28)
Decreased earnings quarter-over-quarter at NSPI due to increased operating, maintenance and general expenses (“OM&G”) primarily driven by costs related to the Cybersecurity Incident and higher depreciation, partially offset by increased sales volumes. Increased earnings year-over-year due to investment tax credits (“ITCs”) related to clean technology investments and increased sales volumes primarily driven by favourable weather, partially offset by higher depreciation and higher OM&G primarily driven by costs related to the Cybersecurity Incident		(12)		41
Corporate
Decreased OM&G primarily due to the timing of the recognition on long term compensation expense and related hedges		6		24
Increased income tax recovery due to decreased deferred income tax asset valuation allowance due to utilization of tax loss carryforwards		6		7
Increased interest expense primarily due to increased total debt, partially offset by lower interest rates		(2)		(7)
Other Variances		8		(1)
Adjusted net income – 2025	$	236	$	615

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


For the	Six months ended June 30
millions of dollars	2025		2024
Operating cash flow before changes in working capital	$	1,306	$	1,244
Changes in working capital		(507)		(51)
Operating cash flow	$	799	$	1,193
Investing cash flow	$	(1,672)	$	(415)
Financing cash flow	$	877	$	(998)

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


As at	June 30		December 31
millions of dollars	2025		2024
Total assets	$	42,531	$	42,951
Total long-term debt (including current portion) (1)	$	18,423	$	18,407

(1) Excludes NMGC balances classified as held for sale as at June 30, 2025. For further details refer to the “Other Developments” section and Note 3 in the condensed consolidated interim financial statements.

Consolidated Income Statement Highlights


For the	Three months ended						Six months ended
millions of dollars	June 30						June 30
(except per share amounts)	2025		2024		Variance		2025		2024		Variance
Operating revenues	$	1,988	$	1,617	$	371	$	4,664	$	3,635	$	1,029
Operating expenses		1,693		1,429		(264)		3,444		3,010		(434)
Income from operations	$	295	$	188	$	107	$	1,220	$	625	$	595
Other income, net	$	85	$	190	$	(105)	$	116	$	218	$	(102)
Income tax (recovery) expense	$	(9)	$	21	$	30	$	110	$	49	$	(61)
Net income attributable to common shareholders	$	135	$	129	$	6	$	718	$	336	$	382
Adjusted net income	$	236	$	151	$	85	$	615	$	367	$	248
Weighted average shares of common stock outstanding (in millions)		298.6		287.3		11.3		297.8		286.2		11.6
EPS – basic	$	0.45	$	0.45	$	-	$	2.41	$	1.17	$	1.24
EPS – diluted	$	0.45	$	0.45	$	-	$	2.41	$	1.17	$	1.24
Adjusted EPS – basic	$	0.79	$	0.53	$	0.26	$	2.07	$	1.28	$	0.79
Dividends per common share declared	$	0.7250	$	0.7175	$	0.0075	$	1.4500	$	1.4350	$	0.0150
Adjusted EBITDA	$	829	$	695	$	134	$	1,835	$	1,490	$	345

Operating Revenues

For Q2 2025, operating revenues increased $371 million compared to Q2 2024 and, excluding the change in MTM impacts, increased $299 million. The increase was due to higher storm cost recoveries at TEC and NSPI (offset in OM&G); new base rates at TEC and NMGC; higher regulatory deferral revenue at TEC; the impact of a weaker CAD; increased sales volumes at TEC primarily driven by favourable weather and customer growth; higher marketing and trading margin at EES; and higher off-system sales at PGS.

Year-to-date 2025, operating revenues increased $1,029 million compared to 2024 and, excluding the change in MTM impacts, increased $667 million. The increase was due to the impact of a weaker CAD; new base rates at TEC and NMGC; higher storm cost recoveries at TEC and NSPI (offset in OM&G); higher regulatory deferral revenue at TEC; increased marketing and trading margin at EES; increased sales volumes at NSPI and TEC primarily driven by favourable weather and customer growth; and higher off-system sales at PGS.

Operating Expenses

For Q2 2025, operating expenses increased $264 million compared to Q2 2024 and, excluding charges related to the pending sale of NMGC of $75 million, increased $189 million. Year-to-date operating expenses increased $434 million compared to 2024 and, excluding the charges related to the pending sale of NMGC of $75 million, increased $359 million. These increases were due to higher natural gas prices at TEC and PGS; higher storm cost recognition at TEC and NSPI (offset in revenue); increased depreciation expense at TEC, PGS and NMGC; and higher OM&G at NSPI. These were partially offset by lower OM&G at Corporate primarily due to the timing of the recognition on long term compensation expense and related hedges. The year-over-year increase was also due to the impact of a weaker CAD.

Other Income, net

For Q2 2025, other income, net decreased $105 million and, year-to-date, decreased $102 million compared to the same periods in 2024. The decrease was due to the gain on sale of LIL in 2024, partially offset by higher FX gains at Corporate in 2025.

Income Tax (Recovery) Expense

For Q2 2025, income tax recovery increased $30 million compared to Q2 2024 due to the impact of the gain on sale of LIL in 2024; increased ITCs related to clean technology investments at NSPI; increased production tax credits related to solar facilities at TEC; and decreased deferred income tax asset valuation allowance. These were partially offset by increased income before provision for income taxes (excluding the gain on sale of LIL in 2024 and charges related to the pending sale of NMGC).

Year-to-date 2025, income tax expense increased $61 million compared to 2024 due to increased income before provision for income taxes (excluding the gain on sale of LIL in 2024 and charges related to the pending sale of NMGC). This was partially offset by the tax impact of the gain on sale of LIL in 2024; increased ITCs related to clean technology investments at NSPI; increased production tax credits related to solar facilities at TEC; and decreased deferred income tax asset valuation allowance.

Net Income and Adjusted Net Income

For Q2 2025, net income attributable to common shareholders, compared to Q2 2024, was favourably impacted by the $100 million decrease in MTM losses and unfavourably impacted by the $72 million charges related to the pending sale of NMGC and the $107 million gain on sale of LIL recognized in Q2 2024. Excluding these impacts, adjusted net income increased $85 million, primarily due to increased earnings at TEC, EES, and NMGC; higher Corporate income tax recovery; and decreased Corporate OM&G. These were partially offset by lower earnings at NSPI; decreased equity earnings from LIL; and increased Corporate interest expense.

Year-to-date 2025 net income attributable to common shareholders, compared to the same period in 2024, was favourably impacted by the $313 million increase in MTM gain and unfavourably impacted by the $72 million charges related to the pending sale of NMGC and the $107 million gain on sale of LIL recognized in 2024. Excluding these changes, adjusted net income increased $248 million. The increase was primarily due to increased earnings at TEC, NSPI, EES, and NMGC; higher Corporate income tax recovery, and decreased Corporate OM&G. These were partially offset by decreased equity earnings from LIL; and increased Corporate interest expense.

EPS – Basic and Adjusted EPS – Basic

For Q2 2025, EPS – basic is consistent with Q2 2024. For Q2 2025, adjusted – EPS was higher than in Q2 2024 due to increased earnings, as discussed above, partially offset by the impact of an increase in weighted average shares outstanding.

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

Effect of Foreign Currency Translation

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

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


	Three months ended				Six months ended				Year ended
	June 30				June 30				December 31
For the	2025		2024		2025		2024		2024
Weighted average CAD/USD	$	1.40	$	1.37	$	1.43	$	1.35	$	1.36
Period end CAD/USD exchange rate	$	1.36	$	1.37	$	1.36	$	1.37	$	1.44

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


	Three months ended						Six months ended
For the	June 30						June 30
millions of USD	2025			2024			2025			2024
Florida Electric Utility	$	188		$	136		$	302		$	199
Gas Utilities and Infrastructure (1)		31			28			110			97
Other Electric Utilities		9			5			9			12
Other segment (2)		(55	)		(50	)		(50	)		(50	)
Total (3)	$	173		$	119		$	371		$	258

(1) Includes USD adjusted net income from PGS, NMGC, SeaCoast and M&NP.

(2) Includes Emera Energy’s USD adjusted net income from EES, Bear Swamp and interest expense on Emera Inc.’s USD denominated debt.

(3) Excludes $45 million USD MTM loss, after-tax, for the three months ended June 30, 2025 (2024 – $88 million USD MTM loss, after-tax) and $98 million USD MTM gain, after-tax, for the six months ended June 30, 2025 (2024 – $89 million USD MTM loss, after-tax).

The translation impact of a weaker CAD on USD earnings increased adjusted net income by $1 million in Q2 2025 and $15 million year-to-date compared to the same periods in 2024 and increased net income attributable to common shareholders by $32 million in Q2 2025 and $62 million year-to-date compared to the same periods in 2024. Impacts of the changes in the translation of the CAD include the impacts of Corporate FX hedges used to mitigate translation risk of USD earnings in the Other segment.

BUSINESS OVERVIEW AND OUTLOOK

There have been no material changes in Emera’s business overview and outlook from the Company’s 2024 annual MD&A, except for the updates disclosed below. The extent of the future impact of trade disputes and tariffs on the Company’s financial results and business operations continues to evolve, cannot be predicted at this time and will depend on future developments. To date, there has been no material financial impact on the Company. For information on risks associated with trade disputes and the imposition of tariffs, refer to the “Enterprise Risk and Risk Management” section in Emera’s 2024 annual MD&A.

Florida Electric Utility

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

On February 3, 2025, the FPSC issued the final order approving the rate case decision, effective January 1, 2025. For additional details on the rate case decision, refer to note 7 in Emera’s 2024 annual audited consolidated financial statements. In February 2025, a motion for reconsideration on certain aspects of the final order was filed by an intervening party with the FPSC. On May 6, 2025, the FPSC denied the motion for reconsideration, except with respect to immaterial calculation corrections, and the final order was issued on June 11, 2025. In March 2025, two intervening parties each filed a notice of appeal to the Florida Supreme Court regarding the outcome of TEC’s 2024 base rate proceeding. As of August 8, 2025, the intervening parties have not filed their briefs related to the appeal.

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

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

Canadian Electric Utilities

NSPI

NSPI anticipates earning below its allowed ROE range in 2025. NSPI expects earnings in 2025 to be higher than 2024. Sales volumes are expected to be higher in 2025 than 2024.

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

In 2025, capital investment, including AFUDC, is expected to be $680 million (2024 – $487 million). NSPI is primarily investing in capital projects required to support power system reliability and reliable service for customers.

NSPML

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

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

On May 21, 2025, NSPML submitted an application to the NSEB for approval of a $33 million capital investment relating to submarine cable protection, which is expected to be incurred in 2026. A decision is expected in Q4 2025.

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

NSPML does not anticipate any significant capital investment in 2025.

Gas Utilities and Infrastructure

PGS

PGS anticipates earning at the bottom of its allowed ROE range in 2025. USD earnings for 2025 are expected to be consistent with 2024 primarily due to higher operating costs and depreciation driven by ongoing capital investments to support customer demand and system needs.

On March 31, 2025, PGS filed a rate case with the FPSC for new rates to become effective January 2026. PGS requested a $93 million USD increase in annual base rates, revised from the original request of $104 million USD, 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. On August 6, 2025, a motion to suspend the procedural schedule was jointly filed with the intervening parties to the base rate case notifying the FPSC that the parties have reached a comprehensive settlement agreement in principle, the details of which are expected to be filed with the FPSC in mid-August 2025 and subject to FPSC approval.

In 2025, capital investment, including AFUDC, is expected to be approximately $360 million USD (2024 – $323 million USD). PGS will make investments to maintain the reliability of its system and support customer growth.

NMGC

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

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

Other Electric Utilities

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

In 2025, capital investment in the Other Electric Utilities segment is expected to be approximately $140 million USD, including AFUDC (2024 – $59 million USD), primarily in more efficient and cleaner sources of generation, including renewables and battery storage.

GBPC

On June 1, 2024, the Electricity Act, 2024 took effect. The legislation purports to remove the jurisdiction of the GBPA over GBPC and to have the Utilities Regulation and Competition Authority (“URCA”), another Bahamian regulator, regulate GBPC. URCA filed a claim in the Supreme Court of the Bahamas, seeking an order that the GBPA be prohibited and restrained from considering and/or approving any adjustment to rates sought by GBPC. URCA contends that it has regulatory authority over electricity provision on Grand Bahama pursuant to the Electricity Act. Management does not foresee that the outcome of the proceedings will have a material impact to Emera.

Other

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

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

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

CONSOLIDATED BALANCE SHEET HIGHLIGHTS

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


	Total
	Increase
millions of dollars	(Decrease)		Explanation of Increase (Decrease)
Assets
Derivative instruments (current and long-term)	$	55	Increased due to new contracts and changes in existing positions at EES, and changes in FX hedges at Corporate, partially offset by decreased FX forward contract balances at NSPI
Regulatory assets (current and long-term)		(154)	Decreased due to lower storm costs recovery assets at TEC and NSPI and the effect of FX translation of Emera’s non-Canadian affiliates. These were partially offset by increased deferred income tax regulatory asset and deferrals related to the fuel adjustment mechanism (“FAM”) at NSPI
Receivables and other assets (current and long-term)		286	Increased due to higher operating revenue at TEC, timing of accounts receivable and higher income tax receivable due to clean technology ITCs at NSPI, partially offset by decreased cash collateral positions on derivative instruments at EES and NSPI
Assets held for sale (current and long-term), net of liabilities (1)		(120)	Decreased primarily due to non-cash impairment charge recognized in 2025, and the effect of FX translation of Emera’s non-Canadian affiliates
Goodwill		(304)	Decreased due to the effect of FX translation of Emera’s non-Canadian affiliates
Liabilities and Equity
Short-term debt and long-term debt (including current portion)	$	351	Increased due to issuance of long-term debt at TEC, and proceeds from issuance of a non-revolving term credit facility at NSPI, partially offset by the effect of FX translation of Emera’s non-Canadian affiliates and repayment of committed credit facilities at TEC and PGS
Accounts payable		(205)	Decreased due to storm cost payments at TEC, lower commodity prices at EES and the effect of FX translation of Emera’s non-Canadian affiliates, partially offset by timing of accounts payable at NSPI
Deferred income tax liabilities, net of deferred income tax assets		61	Increased due to changes in derivative instruments at EES
Derivative instruments (current and long-term)		(192)	Decreased due to changes in existing positions, partially offset by new contracts at EES
Regulatory liabilities (current and long-term)		(213)	Decreased due to lower cost recovery clause liabilities at TEC, lower FAM liability at NSPI, and the effect of FX translation of Emera’s non-Canadian affiliates
Common stock		186	Increased due to shares issued
Accumulated other comprehensive income		(601)	Decreased due to the effect of FX translation of Emera’s non-Canadian affiliates
Retained earnings		287	Increased due to net income in excess of dividends paid

(1) On August 5, 2024, Emera announced the sale of NMGC. As at June 30, 2025 NMGC’s assets and liabilities were classified as held for sale. For further details, refer to the ‘Other Developments’ section and note 3 in the condensed consolidated interim financial statements.

OTHER DEVELOPMENTS

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 United States (“US”). There was no disruption to any of the Company’s Canadian physical operations, including at NSPI’s generation, transmission and distribution facilities, the Maritime Link, or the Brunswick Pipeline. There was no impact to Emera’s US or Caribbean utilities’ operations. The post-incident investigation and assessment of the full financial and other impacts of the Cybersecurity Incident is ongoing.

During restoration efforts, 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 ongoing and will continue in a planned, controlled and phased approach. For more information on the impact on internal controls over financial reporting, refer to the “Disclosure and Internal Controls” section. The Company maintains cyber insurance coverage and is working with its insurer on the claims process. At this time, the Cybersecurity Incident is not expected to have a material impact on the Company’s financial position or results of operations. For information on risks associated with cybersecurity incidents generally, refer to the ‘Enterprise Risk and Risk Management’ section of Emera’s annual 2024 MD&A.

Pending Sale of NMGC

On August 5, 2024, Emera entered into an agreement to sell its indirect wholly-owned subsidiary NMGC for a total enterprise value of approximately $1.3 billion USD, consisting of cash proceeds and the transfer of debt and customary closing adjustments. As a result of the pending sale, NMGC’s assets and liabilities were classified as held for sale in Q3 2024 and the carrying value of the assets and liabilities were adjusted to FV less cost to sell. In July 2025, the procedural schedule for the NMPRC regulatory process was revised with the public hearing rescheduled from June 2025 to early November 2025. The transaction is now expected to close in early 2026.

On June 30, 2025, the Company remeasured the NMGC disposal group at the lower of its carrying value amount and FV less costs to sell by comparing the FV of expected transaction proceeds to the carrying value of net assets. 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 Charge” 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.

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 $61 million ($44 million USD) was recorded on these assets from August 5, 2024, the date they were classified as held for sale, through June 30, 2025. Of the $61 million ($44 million USD) recorded to date, $26 million ($19 million USD) was recorded in 2024.

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. Emera is currently evaluating the impact of the enacted changes but does not anticipate that they will have a material impact on the Company.

New York Stock Exchange (“NYSE”) Listing

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

FINANCIAL HIGHLIGHTS

Florida Electric Utility


	Three months ended				Six months ended
For the	June 30				June 30
millions of USD (except as indicated)	2025		2024		2025		2024
Operating revenues – regulated electric	$	839	$	672	$	1,488	$	1,220
Regulated fuel for generation and purchased power	$	188	$	166	$	349	$	307
Contribution to consolidated net income	$	188	$	136	$	302	$	199
Contribution to consolidated net income – CAD	$	260	$	187	$	424	$	272
Electric sales volumes (Gigawatt hours (“GWh”))		5,400		5,293		10,036		9,643
Electric production volumes (GWh)		5,925		5,885		10,561		10,356
Average fuel cost in dollars per megawatt hour (“MWh”)	$	32	$	28	$	33	$	30

The impact of the change in FX rates increased CAD earnings for the three and six months ended June 30, 2025, by $3 million and $13 million, respectively.

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


For the	Three months ended		Six months ended
millions of USD	June 30		June 30
Contribution to consolidated net income – 2024	$	136	$	199
Increased operating revenues primarily due to new base rates, the impact of favourable weather ($13 million quarter-over-quarter and $18 million year-over-year), customer growth and higher regulatory deferral revenue and storm cost recovery revenue (offset in OM&G)		167		268
Increased fuel for generation and purchased power due to higher natural gas prices		(22)		(42)
Increased OM&G due to higher storm cost recognition (offset in revenue), partially offset by the timing of regulatory deferrals		(63)		(72)
Increased depreciation and amortization due to facilities and capital projects placed in service		(11)		(21)
Increased interest expense due to higher borrowings		(6)		(8)
Increased income tax expense primarily due to higher income before provision for income taxes, partially offset by higher benefit from production tax credits related to solar facilities		(14)		(24)
Other		1		2
Contribution to consolidated net income – 2025	$	188	$	302

Canadian Electric Utilities


	Three months ended				Six months ended
For the	June 30				June 30
millions of dollars (except as indicated)	2025		2024		2025		2024
Operating revenues – regulated electric	$	436	$	423	$	1,035	$	977
Regulated fuel for generation and purchased power (1)	$	215	$	192	$	574	$	482
Contribution to consolidated net income	$	17	$	42	$	138	$	129
Electric sales volumes (GWh)		2,373		2,381		5,706		5,564
Electric production volumes (GWh)		2,497		2,500		6,086		5,933
Average fuel costs in dollars per MWh	$	86	$	77	$	94	$	81

(1) Regulated fuel for generation and purchased power includes NSPI’s FAM on the Condensed Consolidated Statements of Income, however, it is excluded in the segment overview.

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


	Three months ended				Six months ended
For the	June 30				June 30
millions of dollars	2025		2024		2025		2024
NSPI	$	6	$	18	$	116	$	75
Equity investment in NSPML		11		13		22		26
Equity investment in LIL (1)		-		11		-		28
Contribution to consolidated net income	$	17	$	42	$	138	$	129

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

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


For the	Three months ended		Six months ended
millions of dollars	June 30		June 30
Contribution to consolidated net income – 2024	$	42	$	129
Increased operating revenue at NSPI due to higher fuel and storm cost recoveries and higher residential and commercial sales volumes, partially offset by lower industrial sales volumes. Year-over-year increase also due to favourable weather		13		58
Increased regulated fuel for generation and purchased power due to changes in generation mix, lower Nova Scotia output-based pricing system carbon tax, and lower Maritime Link assessment. Year-over-year increase also due to higher sales volumes		(23)		(92)
Increased FAM primarily due to higher under-recovery of fuel costs		15		64
Increased OM&G at NSPI due to lower storm costs deferral, higher costs for power generation operations and costs related to the Cybersecurity Incident. These costs were partially offset by higher administrative overhead allocated to property, plant and equipment (“PP&E”). Year-over-year also partially offset by lower storm restoration costs		(14)		(17)
Increased depreciation and amortization due to increased PP&E in service		(5)		(9)
Decreased income from equity investments due to the sale of LIL		(11)		(28)
Increased income tax recovery primarily due to clean technology investment tax credits in 2025		5		38
Other		(5)		(5)
Contribution to consolidated net income – 2025	$	17	$	138

Gas Utilities and Infrastructure


	Three months ended				Six months ended
For the	June 30				June 30
millions of USD (except as indicated)	2025		2024		2025		2024
Operating revenues – regulated gas (1)	$	256	$	236	$	681	$	627
Operating revenues – non-regulated		4		3		8		7
Total operating revenue	$	260	$	239	$	689	$	634
Regulated cost of natural gas	$	53	$	40	$	206	$	174
Contribution to consolidated net income	$	35	$	32	$	118	$	105
Contribution to consolidated net income – CAD	$	48	$	44	$	168	$	142
Gas sales volumes (millions of Therms)		759		731		1,616		1,641

(1) Operating revenues – regulated gas includes $11 million of finance income from Brunswick Pipeline (2024 – $12 million) for the three months ended June 30, 2025 and $23 million (2024 – $23 million) for the six months ended June 30, 2025.

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


	Three months ended				Six months ended
For the	June 30				June 30
millions of USD	2025		2024		2025		2024
PGS	$	25	$	26	$	65	$	68
NMGC		2		(3)		36		19
Other		8		9		17		18
Contribution to consolidated net income	$	35	$	32	$	118	$	105

The impact of the change in FX rates increased CAD earnings for the three and six months ended June 30, 2025 by $1 million and $8 million, respectively.

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


For the	Three months ended		Six months ended
millions of USD	June 30		June 30
Contribution to consolidated net income – 2024	$	32	$	105
Increased gas revenues due to higher fuel revenue and off-system sales at PGS and new base rates at NMGC		21		55
Increased cost of natural gas due to higher natural gas prices at PGS		(13)		(32)
Increased depreciation primarily due to asset growth at PGS and NMGC		(3)		(6)
Other		(2)		(4)
Contribution to consolidated net income – 2025	$	35	$	118

Other Electric Utilities


	Three months ended				Six months ended
For the	June 30				June 30
millions of USD (except as indicated)	2025		2024		2025		2024
Operating revenues – regulated electric	$	104	$	104	$	196	$	196
Regulated fuel for generation and purchased power	$	53	$	54	$	100	$	102
Contribution to consolidated adjusted net income	$	9	$	5	$	9	$	12
Contribution to consolidated adjusted net income – CAD	$	12	$	8	$	12	$	17
Equity securities MTM gain	$	1	$	-	$	1	$	1
Contribution to consolidated net income	$	10	$	6	$	10	$	13
Contribution to consolidated net income – CAD	$	14	$	8	$	14	$	18
Electric sales volumes (GWh)		325		333		628		638
Electric production volumes (GWh)		346		358		668		685
Average fuel costs in dollars per MWh	$	153	$	151	$	150	$	149

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


	Three months ended				Six months ended
For the	June 30				June 30
millions of USD	2025		2024		2025		2024
BLPC	$	4	$	5	$	6	$	10
GBPC		5		2		3		4
Other		-		(2)		-		(2)
Contribution to consolidated adjusted net income	$	9	$	5	$	9	$	12

The impact of the change in FX rates on CAD earnings for the three and six months ended June 30, 2025 was minimal.

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


For the	Three months ended		Six months ended
millions of USD	June 30		June 30
Contribution to consolidated net income – 2024	$	6	$	13
Increased income tax expense due to the remeasurement of deferred income tax liabilities as a result of a corporate income tax rate change at BLPC		-		(2)
Increased MTM gain on equity securities held at BLPC		1		-
Other		3		(1)
Contribution to consolidated net income – 2025	$	10	$	10

Other


	Three months ended				Six months ended
For the	June 30				June 30
millions of dollars	2025		2024		2025		2024
Marketing and trading margin (1) (2)	$	(19)	$	(31)	$	101	$	49
Other non-regulated operating revenue		7		6		16		15
Total operating revenues – non-regulated	$	(12)	$	(25)	$	117	$	64
Contribution to consolidated adjusted net (loss) income	$	(101)	$	(130)	$	(127)	$	(193)
Charges related to the pending sale of NMGC, after-tax (3)		(72)		-		(72)		-
Gain on sale of LIL, after-tax (4)(5)		-		107		-		107
MTM (loss) gain, after-tax (6)		(31)		(129)		173		(139)
Contribution to consolidated net (loss) income	$	(204)	$	(152)	$	(26)	$	(225)

(1) Marketing and trading margin represents EES’s purchases and sales of natural gas and electricity, pipeline and storage capacity costs and energy asset management services’ revenues.

(2) Marketing and trading margin excludes a pre-tax MTM loss of $91 million for the three months ended June 30, 2025 (2024 – $162 million loss) and a gain of $197 million for the six months ended June 30, 2025 (2024 – $161 million loss).

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

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

(5) Net of income tax expense of $75 million for the three and six months ended June 30, 2024.

(6) Net of income tax recovery of $13 million for the three months ended June 30, 2025 (2024 – $52 million recovery) and $71 million income tax expense for the six months ended June 30, 2025 (2024 – $56 million recovery).

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


	Three months ended				Six months ended
For the	June 30				June 30
millions of dollars	2025		2024		2025		2024
Emera Energy
EES	$	(14)	$	(24)	$	55	$	21
Other		(3)		1		(4)		2
Corporate – see breakdown of adjusted contribution below		(84)		(102)		(178)		(205)
Block Energy LLC		1		(4)		1		(10)
Other		(1)		(1)		(1)		(1)
Contribution to consolidated adjusted net (loss) income	$	(101)	$	(130)	$	(127)	$	(193)

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


For the	Three months ended		Six months ended
millions of dollars	June 30		June 30
Contribution to consolidated net (loss) income – 2024	$	(152)	$	(225)
Increased marketing and trading margin quarter-over-quarter due to lower transport costs and favourable hedge settlements related to EES’ storage positions. Year-over-year due to favourable weather conditions that led to higher natural gas prices and increased volatility that created profitable opportunities		12		52
Decreased OM&G primarily due to a gain on long-term incentive hedge compared to a loss in prior year, which is offset by long-term compensation expense recognized across Emera’s reportable segments		6		24
Increased interest expense primarily due to increased total debt, partially offset by decreased interest rates		(2)		(7)
Increased income tax recovery quarter-over-quarter due to decreased deferred income tax asset valuation allowance, partially offset by decreased loss before provision for income taxes. Decreased income tax recovery year-over-year due to decreased loss before provision for income taxes, partially offset by decreased deferred income tax asset valuation allowance		5		(4)
Charges related to the pending sale of NMGC, after-tax		(72)		(72)
Gain on sale of LIL, after-tax		(107)		(107)
Decreased MTM loss, after-tax, primarily due to lower amortization of gas transportation assets at EES and a gain on Corporate FX hedges compared to prior year. Year-over-year was also driven by changes in existing positions at EES		98		312
Other		8		1
Contribution to consolidated net (loss) income – 2025	$	(204)	$	(26)

Corporate

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


	Three months ended				Six months ended
For the	June 30				June 30
millions of dollars	2025		2024		2025		2024
Operating expenses (1)	$	(20)	$	(26)	$	(27)	$	(51)
Interest expense		(91)		(89)		(187)		(180)
Income tax recovery		40		34		74		67
Preferred dividends		(19)		(18)		(37)		(36)
Other (2)(3)		6		(3)		(1)		(5)
Corporate adjusted net loss (4)(5)(6)	$	(84)	$	(102)	$	(178)	$	(205)

(1) Operating expenses include OM&G and depreciation.

(2) Other includes realized gains and losses on FX hedges entered into to hedge USD denominated operating unit earnings exposure.

(3) Includes a realized net loss, pre-tax of $2 million ($2 million after-tax) for the three months ended June 30, 2025 (2024 – $3 million net loss, pre-tax and $2 million loss, after-tax) and a $10 million net loss, pre-tax ($7 million after-tax) for the six months ended June 30, 2025 (2024 – $4 million net loss, pre-tax and $3 million loss, after-tax) on FX hedges, as discussed above.

(4) Excludes a MTM gain, after-tax, of $30 million for the three months ended June 30, 2025 (2024 – $10 million loss, after-tax) and a MTM gain, after-tax of $33 million for the six months ended June 30, 2025 (2024 – $12 million loss, after-tax).

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

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

LIQUIDITY AND CAPITAL RESOURCES

The Company generates internally sourced cash from its various regulated and non-regulated energy investments. Utility customer bases are diversified by both sales volumes and revenues among customer classes. Emera’s non-regulated businesses provide diverse revenue streams and counterparties to the business. Circumstances that could affect the Company’s ability to generate cash include changes to global macro-economic conditions, downturns in markets served by Emera, impact of fuel commodity price changes on collateral requirements and timely recoveries of fuel and storm costs from customers, the loss of one or more large customers, regulatory decisions affecting customer rates and the recovery of regulatory assets, and changes in environmental legislation. Emera’s subsidiaries are generally in a financial position to contribute cash dividends to Emera provided they do not breach their debt covenants, where applicable, after giving effect to the dividend payment, and that they maintain their credit metrics.

Emera’s future liquidity and capital needs will be predominately for working capital requirements, ongoing rate base investment, business acquisitions, greenfield development, dividends and debt servicing. Emera has an approximate $20 billion capital investment plan over the 2025 through 2029 period and supports ongoing growth. Capital investments at Emera’s regulated utilities are subject to regulatory approval.

Emera has sufficient liquidity to service debt obligations as they come due to meet any near-term capital investment requirements as currently planned. Emera plans to use cash from operations, debt raised at the utilities, Corporate equity, and proceeds from the pending sale of NMGC to support normal operations, repayment of existing debt, and capital requirements. Debt raised at certain of the Company’s utilities is subject to applicable regulatory approvals. Generally, Corporate equity requirements in support of the Company’s capital investment plan are expected to be funded through issuance of hybrid equity and issuance of common equity through Emera’s DRIP and ATM programs.

Emera has total committed credit facilities with varying maturities that cumulatively provide $2.8 billion CAD and $1.6 billion USD of credit, with approximately $935 million CAD and $799 million USD undrawn and available at June 30, 2025. The Company was holding a cash balance of $204 million, which includes $4 million classified as assets held for sale, related to the pending sale of NMGC, at June 30, 2025. For further discussion, refer to the “Debt Management” section below.

Consolidated Cash Flow Highlights

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


millions of dollars	2025		2024		Change
Cash, cash equivalents, restricted cash, and cash associated with assets held for sale, beginning of period	$	221	$	588	$	(367)
Provided by (used in):
Operating cash flow before changes in working capital		1,306		1,244		62
Change in working capital		(507)		(51)		(456)
Operating activities	$	799	$	1,193	$	(394)
Investing activities		(1,672)		(415)		(1,257)
Financing activities		877		(998)		1,875
Effect of exchange rate changes on cash, cash equivalents, restricted cash, and cash associated with assets held for sale		(7)		13		(20)
Cash, cash equivalents, restricted cash and cash associated with assets held for sale, end of period	$	218	$	381	$	(163)

Cash Flow from Operating Activities

Net cash provided by operating activities decreased $394 million to $799 million for the six months ended June 30, 2025, compared to $1,193 million for the same period in 2024.

Cash from operations before changes in working capital increased $62 million year-over-year. This increase was due to higher marketing and trading margin at EES, higher fuel over-recoveries at PGS, new base rates at TEC and NMGC, and higher storm cost recoveries at TEC. These were partially offset by proceeds from the FAM asset sale to Invest Nova Scotia at NSPI in Q2 2024 and higher fuel under-recoveries at TEC.

Changes in working capital decreased operating cash flows by $456 million year-over-year. This decrease was due to unfavourable changes in accounts payable at TEC due to the timing and payment of storm invoices, unfavourable changes in accounts receivable at TEC due to increased base rates and storm cost recoveries, unfavourable changes in accounts receivable and inventory at NSPI, the recognition of ITCs related to clean technology investments at NSPI, and higher trade receivables at GBPC due to higher rental generation expenses. These were partially offset by favourable changes in cash collateral positions at NSPI and EES and timing of settlements at EES.

Cash Flow from Investing Activities

Net cash used in investing activities increased $1,257 million to $1,672 million for the six months ended June 30, 2025, compared to $415 million for the same period in 2024. The increase was due to the proceeds of $927 million received in 2024 on the sale of LIL and higher capital investment, partially offset by proceeds on the disposal of assets.

Capital investments, including AFUDC, for the six months ended June 30, 2025, were $1,757 million, compared to $1,368 million for the same period in 2024. Details of the 2025 capital investment by segment are shown below:

●

$1,108 million – Florida Electric Utility (2024 – $841 million);

●

$319 million – Canadian Electric Utilities (2024 – $222 million);

●

$288 million – Gas Utilities and Infrastructure (2024 – $265 million);

●

$41 million – Other Electric Utilities (2024 – $37 million); and

●

$1 million – Other (2024 – $3 million).

Cash Flow from Financing Activities

Net cash provided by financing activities increased $1,875 million to $877 million for the six months ended June 30, 2025, compared to cash used in financing activities of $998 million for the same period in 2024. This increase was due to lower net repayments under committed credit facilities at Emera and TEC, higher proceeds from short-term debt at NSPI, higher net borrowing on committed credit facilities at NSPI, lower retirement of long-term debt at Emera US Finance LP and, higher proceeds from long-term debt at TEC. These were partially offset by lower issuance of long-term debt at EUSHI Finance Inc., higher repayments of short-term debt at Emera and TECO Finance Inc., and higher retirement of long-term debt at NSPI.

Contractual Obligations

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


millions of dollars	2025		2026		2027		2028		2029		Thereafter		Total
Long-term debt principal (1)(2)	$	23	$	1,257	$	87	$	830	$	1,895	$	15,123	$	19,215
Interest payment obligations (3)(4)		467		909		880		875		792		13,753		17,676
Purchased power (5)		180		316		407		384		376		4,535		6,198
Transportation (6)(7)		433		615		542		454		406		3,411		5,861
Fuel, gas supply and storage (8)		448		408		90		41		40		94		1,121
Capital projects		272		111		28		3		-		-		414
Asset retirement obligations		10		3		3		5		3		430		454
Pension and post-retirement obligations (9)		16		31		66		70		70		216		469
Other		87		95		56		43		43		257		581
	$	1,936	$	3,745	$	2,159	$	2,705	$	3,625	$	37,819	$	51,989

As detailed below, contractual obligations at June 30, 2025 includes those related to NMGC. On completion of the sale of NMGC, all remaining future contractual obligations will be transferred to the buyer. For further details on the pending transaction, refer to the “Other Developments” section.

(1) Includes $660 million related to NMGC (2026: $95 million and $565 million thereafter).

(2) The Company’s $1.2 billion USD and $500 million USD hybrid notes mature in 2076 and 2054, respectively, and these maturity dates have been used in the computation of the Company’s long-term debt principal and interest payment obligations at June 30, 2025.The Company has the option to repay such notes in advance of maturity upon exercise of the Company’s redemption rights in accordance with the terms of the applicable indenture. Emera’s $1.2 billion USD hybrid notes are redeemable, at Emera’s option, in June 2026.

(3) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at June 30, 2025, including any expected required payment under associated swap agreements.

(4) Includes $322 million related to NMGC (2025: $12 million, 2026: $24 million, 2027: $22 million, 2028: $22 million, 2029: $22 million, and $220 million thereafter).

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

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

(7) Includes $74 million related to NMGC (2025: $13 million, 2026: $23 million, 2027: $15 million, 2028: $12 million, and 2029: $3 million and $8 million thereafter).

(8) Includes $215 million related to NMGC (2025: $70 million, 2026: $129 million, 2027: $13 million, and 2028: $3 million).

(9) Includes the estimated contractual obligation, which is calculated as the current legislatively required contributions to the registered funded pension plans, plus the estimated costs of further benefit accruals contracted under NSPI’s Collective Bargaining Agreement and estimated benefit payments related to other unfunded benefit plans.

NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. In November 2024, the NSEB approved the collection of up to $197 million from NSPI for the recovery of Maritime Link costs in 2025. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to NSEB approval.

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

Debt Management

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


							Undrawn
			Credit				and
millions of dollars in currency as noted below	Maturity		Facilities		Utilized		Available
In CAD:
Emera – committed revolving credit facility		June 2029	$	1,300	$	821	$	479
NSPI – committed revolving credit facility		June 2029		800		344		456
NSPI – non-revolving facility		May 2026		500		500		-
Emera – non-revolving facility		February 2026		200		200		-
In USD:
TEC – committed revolving credit facility		December 2028		800		465		335
TECO Finance, Inc. – committed revolving credit facility		December 2028		400		161		239
PGS – revolving facility		December 2028		250		114		136
NMGC – revolving credit facility		December 2026		125		52		73
Other – committed revolving credit facilities		Various		28		12		16

Emera and its subsidiaries have certain financial and other covenants associated with their debt and credit facilities. Covenants are tested regularly, and the Company is in compliance with covenant requirements as at June 30, 2025.

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

Florida Electric Utility

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

Canadian Electric Utilities

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

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.

Credit Ratings

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

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

Guarantees and Letters of Credit

Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2024 annual MD&A, with material updates as noted below:

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

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 June 30, 2025 was $70 million (December 31, 2024 – $58 million).

Outstanding Stock Data

Common Stock


	millions of		millions of
Issued and outstanding:	shares		dollars
Balance, December 31, 2024		295.94	$	9,042
Issuance of common stock under ATM program (1)		0.19		10
Issued under the DRIP, net of discounts		2.68		153
Senior management stock options exercised and Employee Share Purchase Plan		0.44		23
Balance, June 30, 2025		299.25	$	9,228

(1) For the three months ended June 30, 2025, no common shares were issued under Emera’s ATM program. For the six months ended June 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 June 30, 2025, an aggregate gross sales limit of $326 million remained available for issuance under the ATM program.

As at August 5, 2025, the amount of issued and outstanding common shares was 299.3 million.

If all outstanding stock options were converted as at August 5, 2025, an additional 4.3 million common shares would be issued and outstanding.

Preferred Stock

As at August 5, 2025, Emera had the following preferred shares issued and outstanding: Series A – 4.9 million; Series B – 1.1 million; Series C – 10.0 million; Series E – 5.0 million; Series F – 8.0 million; Series H – 12.0 million; Series J – 8.0 million, and Series L – 9.0 million. Emera’s preferred shares do not have voting rights unless the Company fails to pay, in aggregate, eight quarterly dividends.

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”). There are currently 4,866,814 Series A Shares and 1,133,186 Series B Shares outstanding.

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). Emera also announced a dividend rate of 4.542 per cent on the Series B Shares for the three-month period commencing on August 15, 2025 and ending on (and inclusive of) November 14, 2025 ($0.2862 per Series B Share for the 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 has advised the Holders that no Series A Shares will be converted into Series B Shares and all remaining Series B Shares will automatically be converted into Series A Shares on a one-for-one basis on the Conversion Date. On the Conversion Date, there will be 6 million Series A Shares and no Series B Shares outstanding.

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

TRANSACTIONS WITH RELATED PARTIES

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

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

●

Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Condensed Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $42 million for the three months ended June 30, 2025 (2024 – $40 million) and $91 million for the six months ended June 30, 2025 (2024 – $82 million). NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments. For further details, refer to the “Business Overview and Outlook – Canadian Electric Utilities – NSPML” and “Contractual Obligations” sections.

●

Natural gas transportation capacity purchases from M&NP are reported in the Condensed Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues – non-regulated, totalled $3 million for the three months ended June 30, 2025 (2024 – $2 million) and $11 million for the six months ended June 30, 2025 (2024 – $6 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 June 30, 2025, Emera and its associated companies had $31 million due to related parties (December 31, 2024 – $24 million) recorded in “Other Current Liabilities” on the Condensed Consolidated Balance Sheets.

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

There have been no material changes in Emera’s risk management profile and practices from those disclosed in the Company’s 2024 annual MD&A. In April 2025, Emera and NSPI were impacted by a Cybersecurity Incident, as more particularly described in the “Other Developments” section. For more information on risks associated with cybersecurity generally, refer to the “Enterprise Risk and Risk Management” section of Emera’s 2024 annual MD&A.

Derivative Assets and Liabilities Recognized on the Balance Sheet


As at	June 30		December 31
millions of dollars	2025		2024
Regulatory Deferral:
Derivative instrument assets (1)	$	31	$	45
Derivative instrument liabilities (2)		(34)		(40)
Regulatory assets (1)		35		53
Regulatory liabilities (2)		(18)		(44)
Net asset	$	14	$	14
HFT Derivatives:
Derivative instrument assets (1)	$	166	$	122
Derivative instrument liabilities (2)		(391)		(542)
Net liability	$	(225)	$	(420)
Other Derivatives:
Derivative instrument assets (1)	$	37	$	-
Derivative instrument liabilities (2)		-		(36)
Net asset (liability)	$	37	$	(36)

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

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

Realized and Unrealized Gains (Losses) Recognized in Net Income


	Three months ended				Six months ended
For the	June 30				June 30
millions of dollars	2025		2024		2025		2024
Regulatory Deferral:
Regulated fuel for generation and purchased power (1)	$	(7)	$	(16)	$	(6)	$	(21)
HFT Derivatives:
Non-regulated operating revenues	$	(14)	$	(10)	$	464	$	150
Other Derivatives:
OM&G	$	5	$	(6)	$	25	$	(14)
Other income, net		41		(17)		37		(20)
Net gains (losses)	$	46	$	(23)	$	62	$	(34)
Total net gains (losses)	$	25	$	(49)	$	520	$	95

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

As of June 30, 2025, the unrealized gain in accumulated other comprehensive income was $11 million, after-tax (December 31, 2024 – $12 million, after-tax). For the three and six months ended June 30, 2025, unrealized gains of $1 million (nil and $1 million for the three and six months ended June 30, 2024, respectively) have been reclassified into interest expense.

DISCLOSURE AND INTERNAL CONTROLS

Management is responsible for establishing and maintaining adequate disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings. The Company’s internal control framework is based on criteria published in the Internal Control - Integrated Framework (2013), a report issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer, designed the Company’s DC&P and ICFR as at June 30, 2025, to provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.

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

Change in ICFR

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

There were no other changes in the Company’s ICFR during the quarter ended June 30, 2025 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

CRITICAL ACCOUNTING ESTIMATES

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

CHANGES IN ACCOUNTING POLICIES AND PRACTICES

Future Accounting Pronouncements

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

Disaggregation of Income Statement Expenses

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

Improvements to Income Tax Disclosures

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

SUMMARY OF QUARTERLY RESULTS


For the quarter ended
millions of dollars	Q2		Q1		Q4		Q3		Q2		Q1		Q4		Q3
(except per share amounts)	2025		2025		2024		2024		2024		2024		2023		2023
Operating revenues	$	1,988	$	2,676	$	1,763	$	1,802	$	1,617	$	2,018	$	1,972	$	1,740
Net income attributable to common shareholders	$	135	$	583	$	154	$	4	$	129	$	207	$	289	$	101
EPS – basic	$	0.45	$	1.96	$	0.52	$	0.01	$	0.45	$	0.73	$	1.04	$	0.37
EPS – diluted	$	0.45	$	1.96	$	0.52	$	0.01	$	0.45	$	0.73	$	1.04	$	0.37

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

Q2 2025 compared to Q2 2024

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

Q1 2025 compared to Q1 2024

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

Q4 2024 compared to Q4 2023

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

Q3 2024 compared to Q3 2023

Q3 2024 net income attributable to common shareholders decreased by $97 million and EPS – basic and diluted decreased by $0.36 compared to Q3 2023. The decreases were primarily due to charges related to the pending sale of NMGC; decreased earnings at Emera Energy; lower equity earnings from LIL; lower Corporate income tax recovery due to decreased losses before provision for income taxes; increased Corporate interest expense due to increased interest rates and increased total debt; and increased Corporate preferred share dividends. These changes were partially offset by decreased MTM losses; increased earnings at TEC, PGS, NSPI and NMGC; and lower Corporate OM&G due to the timing difference in the valuation of long-term incentive expense and related hedges. The change in EPS was also impacted by an increase in weighted average shares outstanding.

EMERA INC 6-K