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Management’s Discussion & Analysis

As at August 7, 2026

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, 2026 relative to the same periods in 2025; and its financial position as at June 30, 2026 relative to December 31, 2025. 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, 2026; and the Emera annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2025. 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, 2026, 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”)
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”)
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

On May 12, 2026, Emera completed the sale of Grand Bahama Power Company Limited (“GBPC”). For further details, refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.

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		9
Business Overview and Outlook		12
Florida Electric Utility		12
Canadian Electric Utilities		12
Gas Utilities and Infrastructure		13
Other Electric Utilities		13
Other		14
Consolidated Balance Sheet Highlights		15
Other Developments		16
Financial Highlights		17
Florida Electric Utility		17
Canadian Electric Utilities		18


Gas Utilities and Infrastructure		19
Other Electric Utilities		20
Other		21
Liquidity and Capital Resources		23
Consolidated Cash Flow Highlights		24
Contractual Obligations		25
Debt Management		26
Credit Ratings		28
Guarantees and Letters of Credit		28
Outstanding Stock Data		29
Transactions with Related Parties		29
Risk Management and Financial Instruments		30
Disclosure and Internal Controls		31
Critical Accounting Estimates		32
Changes in Accounting Policies and Practices		32
Future Accounting Pronouncements		32
Summary of Quarterly Results		33

FORWARD-LOOKING INFORMATION

This MD&A contains “forward-looking information” within the meaning of applicable Canadian securities laws and “forward-looking statements” within the meaning of applicable US securities laws, including without limitation, the United States Private Securities Litigation Reform Act of 1995 (collectively, “FLI”), which reflect the current view with respect to the Company’s expectations regarding future growth, results of operations, performance, earnings, capital investment, sales volumes, recovery of costs, timing of regulatory decisions, the expected timing and outcome of the pending sale of NMGC, the expected impact of the Cybersecurity Incident (as defined herein) on the Company’s financial position and results of operations, information technology (“IT”) systems restoration, insurance recoveries, and business continuity processes as well as other matters relating to the Cybersecurity Incident, business prospects and opportunities, and may not be appropriate for other purposes. 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; system operating and maintenance risks; uninsured risk; changes in economic conditions; commodity price and availability risk; liquidity and capital markets risk; general economic 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 from challenges in the global economy; potential impacts of trade disputes and tariffs; estimated energy consumption rates; maintenance of adequate insurance coverage and receipt of proceeds; changes in customer energy usage patterns; developments in technology that could impact demand for electricity; climate risk; weather risk, including higher frequency and severity of weather events; risk of wildfires; unanticipated maintenance and other expenditures; derivative financial instruments and hedging; interest rate risk; inflation risk; counterparty risk; disruption of fuel supply; 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 future employee benefit plan performance and funding requirements; loss of service area; risks and costs associated with failure of IT infrastructure and cybersecurity incidents including IT systems restoration and business continuity processes; uncertainties associated with infectious diseases, pandemics and similar public health threats; risks associated with health and safety; project development and land use rights risk; 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 and disclaims any intention to revise or update any FLI as a result of new information, future events or otherwise. Additional detailed information about the above referenced assumptions, risks, uncertainties and other factors is included in Emera’s securities regulatory filings, which can be found on SEDAR+ at www.sedarplus.ca or on EDGAR at www.sec.gov.

INTRODUCTION AND STRATEGIC OVERVIEW

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

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

Earnings opportunities in regulated utilities are a function of the magnitude of net investment in the utility (known as “rate base”), the amount of equity in the capital structure, and the targeted return on that equity (“ROE”), all as established and approved through regulation. Earnings are also affected by sales volumes and operating expenses. In 2025, Emera’s regulated cost-of-service utilities in Florida accounted for 67 per cent of average consolidated rate base, with Atlantic Canada comprising 25 per cent, and the Caribbean and New Mexico 4 per cent each.

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


millions of dollars		2026		2027		2028		2029		2030		Total
Capital investment plan (1)(2)	$	4,020	$	3,730	$	4,140	$	4,180	$	4,330	$	20,400
Average consolidated rate base forecast (1)(2):
US operations	$	23,180	$	25,100	$	27,140	$	29,300	$	31,480
Canadian operations		7,340		7,660		7,990		8,320		8,580
Total	$	30,520	$	32,760	$	35,130	$	37,620	$	40,060

(1) Capital investment plan and average consolidated rate base forecast are updated annually, typically in the second half of the year.

(2) The table above excludes NMGC. For more information on the pending sale of NMGC, refer to the “Other Developments” section.

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 pending close of the NMGC transaction. Generally, Emera’s equity requirements are expected to be funded through the issuance of hybrid securities, and the issuance of common equity through Emera’s dividend reinvestment plan (“DRIP”) and its at-the-market program (“ATM program”). Maintaining investment-grade credit ratings is a core strategic priority of the Company.

Emera has increased dividends per common share paid for 19 consecutive years and has provided annual dividend growth guidance of one to two per cent. Emera anticipates average adjusted EPS growth of five to seven per cent through 2030, using 2024 as the base year, which will support continued reduction in the ratio of dividend payout to adjusted net income over time. 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.

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

•

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

2026: Loss on Sale of GBPC

In Q2 2026, Emera recognized a $19 million loss, after tax and transaction costs, on the sale of GBPC. For further details, refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.

2025: Charges related to the Pending Sale of NMGC

On August 5, 2025, 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” section.

Emera calculates adjusted net income for the Other Electric Utilities and Other segments. Reconciliation to the nearest GAAP measure is included in each segment. For more information, refer to the Financial Highlights section for each of Other Electric Utilities, and Other.

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 2025 annual MD&A.

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


For the	Three months ended June 30				Six months ended June 30
millions of dollars (except per share amounts)	2026		2025		2026		2025
Net income attributable to common shareholders	$	105	$	135	$	667	$	718
Less:
MTM (loss) gain, after-tax (1)		(88)		(29)		59		175
Loss on sale of GBPC, after tax and transaction costs (2)		(19)		-		(19)		-
Charges related to the pending sale of NMGC, after-tax (3)		-		(72)		-		(72)
Adjusted net income	$	212	$	236	$	627	$	615
EPS – basic	$	0.34	$	0.45	$	2.19	$	2.41
Adjusted EPS – basic	$	0.69	$	0.79	$	2.06	$	2.07

(1) Net of income tax recovery of $37 million for the three months ended June 30, 2026 (2025 – $13 million recovery) and $24 million income tax expense for the six months ended June 30, 2026 (2025 – $71 million expense).

(2) Net of income tax recovery of $2 million for the three and six months ended June 30, 2026.

(3) 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. Amounts are net of an income tax recovery of $5 million for the three and six months ended June 30, 2025.

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, loss on sale of GBPC, and 2025 charges related to the pending sale of NMGC.

Reconciliation of Net Income to EBITDA and Adjusted EBITDA


For the	Three months ended June 30				Six months ended June 30
millions of dollars	2026		2025		2026		2025
Net income (1)	$	124	$	154	$	706	$	755
Interest expense, net		275		249		546		504
Income tax (recovery) expense		(25)		(9)		104		110
Depreciation and amortization		336		316		675		635
EBITDA	$	710	$	710	$	2,031	$	2,004
Less: MTM (loss) gain, excluding income tax		(125)		(42)		83		246
Loss on sale of GBPC, excluding income tax		(21)		-		(21)		-
Charges related to the pending sale of NMGC, excluding income tax		-		(77)		-		(77)
Adjusted EBITDA	$	856	$	829	$	1,969	$	1,835
(1) Net income is before Preferred stock dividends.

CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Earnings

2026:

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

MTM loss, after-tax, increased $59 million to $88 million in Q2 2026 compared to $29 million in Q2 2025. Year-to-date, MTM gain, after-tax, decreased $116 million to $59 million in 2026 compared to $175 million for the same period in 2025. These unfavourable changes in MTM, after-tax, were primarily due to a loss on Corporate FX hedges compared to a gain in prior year and amortization of gas transportation assets and changes in existing positions at Emera Energy Services (“EES”).

Loss on Sale of GBPC

On May 12, 2026, Emera completed the sale of GBPC. A loss on sale of $21 million after transaction costs ($19 million, after tax and transaction costs, or $0.06 per common share) was recorded. This was recorded in “Other (expense) income, net” on the Condensed Consolidated Statements of Income and included in the “Other Electric Utilities” and “Other” segments.

As a result of the sale, earnings contributions from GBPC were $7 million lower in Q2 2026 and year-to-date 2026 compared to the same periods in 2025.

2025:

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 unaudited condensed consolidated interim financial statements.

Consolidated Financial Highlights


For the millions of dollars	Three months ended June 30				Six months ended June 30
Adjusted Net Income	2026		2025		2026		2025
Florida Electric Utility	$	261	$	260	$	441	$	424
Canadian Electric Utilities		16		17		102		138
Gas Utilities and Infrastructure		55		48		191		168
Other Electric Utilities		5		12		13		12
Other		(125)		(101)		(120)		(127)
Adjusted net income	$	212	$	236	$	627	$	615
MTM (loss) gain, after-tax		(88)		(29)		59		175
Loss on sale of GBPC, after tax and transaction costs		(19)		-		(19)		-
Charges related to the pending sale of NMGC, after-tax		-		(72)		-		(72)
Net income attributable to common shareholders	$	105	$	135	$	667	$	718

The following table highlights significant quarter-over-quarter and year-over-year changes in adjusted net income from 2025 to 2026:


For the	Three months ended		Six months ended
millions of dollars	June 30		June 30
Adjusted net income – 2025	$	236	$	615
Operating Unit Performance
Increased earnings at PGS due to higher revenue from new base rates and higher off-system sales, partially offset by higher operating, maintenance and general expenses (“OM&G”) and depreciation		15		33
Increased equity earnings at Bear Swamp due to business interruption insurance received related to an unplanned outage in 2025 and higher generation		19		23
Increased earnings year-over-year at TEC due to higher revenue from new base rates and higher off-system sales, partially offset by higher depreciation, increased state and municipal taxes, higher interest expense and the impact of a stronger CAD		1		17
Decreased earnings year-over-year at NSPI due to lower income tax recovery as a result of higher clean technology investment tax credits in 2025 ($18 million), higher OM&G and higher depreciation expense. These were partially offset by higher sales volumes		-		(36)
Decreased earnings due to the sale of GBPC in May 2026		(7)		(7)
Decreased earnings quarter-over-quarter at EES due to timing of hedge settlements related to storage positions and higher transport costs. Increased earnings year-over year due to favourable market conditions that led to higher natural gas prices and increased volatility that created profitable opportunities		(10)		26
Decreased earnings at NMGC primarily due to higher OM&G		(12)		(12)
Corporate
Increased income tax recovery quarter-over-quarter primarily due to an increased loss before provision for income taxes, partially offset by an unfavourable deferred income tax asset valuation adjustment. Increased income tax recovery year-over-year due to an increased loss before provision for income taxes		3		9
Increase OM&G, pre-tax, primarily due to lower gain on the long-term incentive hedge and increased costs as a result of New York Stock Exchange (“NYSE”) listing		(1)		(13)
Increased Corporate FX losses on the translation of USD short-term debt balances. Year-over-year is partially offset by a decreased realized loss on FX hedges		(9)		(4)
Increased interest expense, pre-tax, due to higher long-term debt resulting from the timing of financings, partially offset by interest earned on debt proceeds held in invested cash. Year-over-over is also partially offset by lower short-term debt		(21)		(28)
Other Variances		(2)		4
Adjusted net income – 2026	$	212	$	627

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


For the	Six months ended June 30
millions of dollars	2026		2025
Operating cash flow before changes in working capital	$	1,411	$	1,306
Changes in working capital		(9)		(507)
Operating cash flow	$	1,402	$	799
Investing cash flow	$	(1,531)	$	(1,672)
Financing cash flow	$	95	$	877

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

	$		$
As at		June 30		December 31
millions of dollars		2026		2025
Total assets	$	46,556	$	44,817
Total long-term debt (including current portion) (1)	$	19,587	$	19,654
(1) Excludes NMGC balances classified as held for sale. For further details refer to the “Other Developments” section and note 3 in the unaudited 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)	2026		2025		Variance		2026		2025		Variance
Operating revenues	$	2,011	$	1,988	$	23	$	4,824	$	4,664	$	160
Operating expenses		1,657		1,693		36		3,527		3,444		(83)
Income from operations	$	354	$	295	$	59	$	1,297	$	1,220	$	77
Other (expense) income, net	$	(12)	$	85	$	(97)	$	6	$	116	$	(110)
Income tax (recovery) expense	$	(25)	$	(9)	$	16	$	104	$	110	$	6
Net income attributable to common shareholders	$	105	$	135	$	(30)	$	667	$	718	$	(51)
Adjusted net income	$	212	$	236	$	(24)	$	627	$	615	$	12
Weighted average shares of common stock outstanding (in millions)		306.4		298.6		7.8		304.9		297.8		7.1
EPS – basic	$	0.34	$	0.45	$	(0.11)	$	2.19	$	2.41	$	(0.22)
EPS – diluted	$	0.34	$	0.45	$	(0.11)	$	2.18	$	2.41	$	(0.23)
Adjusted EPS – basic	$	0.69	$	0.79	$	(0.10)	$	2.06	$	2.07	$	(0.01)
Dividends per common share declared	$	0.7325	$	0.7250	$	0.0075	$	1.4650	$	1.4500	$	0.0150
Adjusted EBITDA	$	856	$	829	$	27	$	1,969	$	1,835	$	134

Operating Revenues

For Q2 2026, operating revenues increased $23 million compared to Q2 2025 and, excluding the change in MTM impacts, increased $44 million. The increase was due to new base rates at TEC and PGS; higher fuel cost recoveries at BLPC; and increased commercial and industrial sales volumes at NSPI. These were partially offset by decreased revenues due to the sale of GBPC.

Year-to-date 2026, operating revenues increased $160 million compared to 2025 and, excluding the change in MTM impacts, increased $247 million. The increase was due to higher marketing and trading margin at EES; new base rates at TEC and PGS; increased off-system sales at TEC and PGS; higher storm cost recovery revenue at TEC (offset in OM&G); and increased commercial and industrial sales volumes at NSPI. These were partially offset by the impact of a stronger CAD; lower fuel cost recoveries at NMGC; and decreased revenues due to the sale of GBPC.

Operating Expenses

For Q2 2026, operating expenses decreased $36 million compared to Q2 2025 and, excluding charges related to the pending sale of NMGC of $75 million in 2025, increased $39 million. Year-to-date operating expenses increased $83 million compared to 2025, and excluding charges related to the pending sale of NMGC in 2025, increased $158 million. These increases were due to increased OM&G due to higher labour and benefits at NMGC and PGS; and increased depreciation expense at TEC, PGS and NSPI. Year-over-year increase was also due to higher natural gas prices at TEC and PGS; higher storm costs recognition at TEC (offset in revenue); higher OM&G at Corporate and NSPI, partially offset by the impact of a stronger CAD; and lower natural gas prices at NMGC.

Other (Expense) Income, net

Other income, net decreased $97 million in Q2 2026, compared to the same period in Q2 2025. Year-to-date, other income, net decreased $110 million compared to the same period in 2025. The changes were due to lower unrealized FX gains at Corporate and the loss on sale of GBPC.

Income Tax (Recovery) Expense

For Q2 2026, income tax recovery increased $16 million compared to Q2 2025 due to decreased earnings before provision for income taxes and the tax impact of charges related to the pending sale of NMGC in 2025.

Year-to-date 2026, income tax expense decreased $6 million compared to 2025 due to decreased earnings before provision for income taxes, the tax impact of charges related to the pending sale of NMGC in 2025 and increased tax credits recognized at TEC. This was partially offset by decreased tax credits recognized at NSPI and an unfavourable impact of foreign currency translation.

Net Income and Adjusted Net Income

For Q2 2026, net income attributable to common shareholders, compared to Q2 2025, was unfavourably impacted by the $59 million increase in MTM losses, after-tax, and the $19 million loss on sale of GBPC, after tax and transaction costs, and favourably impacted by the $72 million charges related to the pending sale of NMGC recognized in Q2 2025. Excluding these impacts, adjusted net income decreased $24 million, primarily due to increased interest expense and FX losses on the translation of USD short-term debt balances at Corporate; decreased earnings at NMGC and EES; and lower earnings due to the sale of GBPC. These were partially offset by increased earnings at PGS; and higher equity earnings at Bear Swamp.

Year-to-date 2026, net income attributable to common shareholders, compared to the same period in 2025, was favourably impacted by the $72 million charges related to the pending sale of NMGC recognized in Q2 2025, and unfavourably impacted by the $116 million decrease in MTM gain, after-tax, and the $19 million loss on sale of GBPC. Excluding these changes, adjusted net income increased $12 million. The increase was primarily due to increased earnings at PGS, EES and TEC; higher equity earnings at Bear Swamp and higher income tax recovery at Corporate. These were partially offset by increased interest expense and higher OM&G at Corporate; lower earnings at NSPI and NMGC; and lower earnings due to the sale of GBPC.

EPS – Basic and Adjusted EPS – Basic

For Q2 2026, EPS – basic and adjusted EPS were lower due to the impact of lower earnings and increased weighted average shares outstanding.

Year-over-year, EPS – basic was lower due to the impact of lower earnings and increased weighted average shares outstanding. Adjusted EPS year-over-year was consistent with 2025.

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 2025 annual MD&A.

The relevant CAD/USD exchange rates for 2026 and 2025 are as follows:


	Three months ended June 30				Six months ended June 30				Year ended December 31
	2026		2025		2026		2025		2025
Weighted average CAD/USD	$	1.38	$	1.40	$	1.37	$	1.43	$	1.41
Period end CAD/USD exchange rate	$	1.42	$	1.36	$	1.42	$	1.36	$	1.37

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	2026		2025		2026		2025
Florida Electric Utility	$	189	$	188	$	320	$	302
Gas Utilities and Infrastructure (1)		33		31		128		110
Other Electric Utilities (2)		3		9		10		9
Other segment (3)		(55)		(55)		(30)		(50)
Total (4)	$	170	$	173	$	428	$	371
(1) Includes USD net income from PGS, NMGC, SeaCoast and M&NP.
(2) Excludes $12 million USD, after-tax loss on sale of GBPC for the three and six months ended June 30, 2026.
(3) Includes Emera Energy’s USD adjusted net income from EES, Bear Swamp and interest expense on Emera Inc.’s USD denominated debt.
(4) Excludes $52 million USD MTM loss, after-tax, for the three months ended June 30, 2026 (2025 – $45 million USD MTM loss, after-tax) and $58 million USD MTM gain, after-tax, for the six months ended June 30, 2026 (2025 – $98 million USD MTM gain, after-tax).

Strengthening of the CAD decreased net income attributable to common shareholders by $13 million in Q2 2026 and $43 million year-to-date compared to the same periods in 2025. In Q2 2026, the impact of the change in FX rates on adjusted net income was nil. Year-to-date, strengthening of the CAD decreased adjusted net income by $17 million, compared to the same period in 2025. These impacts include the effect of the FX hedges used to mitigate translation risk of USD earnings, which are included in Corporate 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 2025 annual MD&A, except for the updates disclosed below.

Florida Electric Utility

TEC anticipates earning within its allowed ROE range in 2026. USD earnings are expected to be higher in 2026 than 2025 as a result of new base rates effective January 1, 2026, and continued customer growth.

On April 6, 2026, the FPSC established a docket for further study of certain purchased power costs recovered through the fuel adjustment clause. On April 15, 2026, TEC filed a petition with the FPSC seeking approval of revised depreciation rates for Bayside Station assets, which would decrease annual depreciation expense by approximately $20 million USD. On June 16, 2026, TEC and the Office of Public Counsel filed with the FPSC a motion to approve a settlement agreement for the revised depreciation rates to be effective on July 1, 2026. As part of the settlement agreement, TEC agreed to a decrease fuel clause recovery by $10 million USD in 2026, which will be reflected on customer’s bills in 2027. TEC also agreed to not seek approval for an increase in base revenues effective prior to January 1, 2028, except for previously approved subsequent year adjustments from the 2024 rate case and large load customer tariffs required by statute. On August 4, 2026, the FPSC approved the settlement agreement.

On February 3, 2025, the FPSC issued the final order approving the 2024 rate case decision, effective January 1, 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. On January 12, 2026, the intervening parties filed their briefs related to the appeal. On April 13, 2026, the FPSC and TEC filed responses to the briefs. To date, the Florida Supreme Court has not made a decision regarding this case.

In 2026, capital investment in the Florida Electric Utility segment is expected to be $1.8 billion USD (2025 – $1.6 billion USD), including allowance for funds used during construction (“AFUDC”). Capital projects include investment in generation reliability projects, storm hardening, grid modernization, and transmission expansion.

Canadian Electric Utilities

NSPI

NSPI expects earnings in 2026 to be higher than 2025 as a result of new base rates effective May 1, 2026, as discussed below, but anticipates earning below its allowed ROE range in 2026 primarily due to a delay in the general rate application (“GRA”) decision. Sales volumes are expected to be higher in 2026 than in 2025.

On April 30, 2026, the NSEB approved the GRA with changes effective on May 1, 2026. This results in an average annual customer rate increase of 1.2 per cent, and a further average annual increase of 2.5 per cent on January 1, 2027. The approved rates are expected to result in annual revenue (fuel and non-fuel) increases of $31 million in 2026 and $97 million in 2027. Any under or over-recovery of fuel costs will be addressed through NSPI’s established fuel adjustment mechanism (“FAM”) process with the NSEB. NSPI’s ROE range will continue to be 8.75 per cent to 9.25 per cent, based on a common equity component of up to 40 per cent. The NSEB also approved the depreciation study completed in 2025 and continuation of the storm rider for each of 2026 and 2027. Additionally, the NSEB approved deferral of depreciation and financing costs for assets within the scope of NSPI’s Decarbonization Deferral Account as of December 31, 2025. NSPI has proposed to recover these costs through a rate reducing securitization transaction, the timing of which requires final support from the Province of Nova Scotia.

In 2026, capital investment is expected to be approximately $700 million (2025 – $712 million), including AFUDC. NSPI is primarily investing in capital projects required to support power system reliability and reliable service for customers.

NSPML

Equity earnings from NSPML in 2026 are expected to be consistent with 2025. The NSPML investment is recorded as “Investments subject to significant influence” on Emera’s Consolidated Balance Sheets.

On June 25, 2026, NSPML submitted an application to the NSEB requesting recovery of $200 million in 2027 and $192 million in 2028 for costs associated with the Maritime Link. A decision is expected in Q4 2026.

On May 11, 2026, the NSEB issued its decision on NSPML’s 2026 assessment application, reducing NSPML’s approved regulated ROE from 9.0 per cent to 8.75 per cent and approved the collection of up to $198 million in Maritime Link costs for 2026, subject to a monthly holdback of up to $4 million if certain delivery requirements are not met. There was no holdback recorded year-to-date in 2026.

In 2026, capital investment at NSPML is expected to be approximately $40 million (2025 – $7 million).

Gas Utilities and Infrastructure

PGS

PGS anticipates earning within its allowed ROE range in 2026. USD earnings are expected to be higher in 2026 than 2025, as a result of new base rates effective January 1, 2026, favourable market conditions for off system sales revenue and continued customer growth.

In 2026, capital investment is expected to be approximately $445 million USD (2025 – $323 million USD), including AFUDC. PGS will make investments to maintain the reliability of their systems 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 as of Q3 2024. On July 30, 2026, the NMPRC issued a final order approving the transaction, which is expected to close in August 2026. For more information on the pending transaction, refer to the “Other Developments” section.

NMGC’s USD earnings contribution to Emera in 2026 are expected to be lower than in 2025 as a result of the pending sale of NMGC and the resulting partial-year earnings contribution.

Other Electric Utilities

On May 12, 2026, Emera completed the sale of GBPC. For further details, refer to the “Other Developments” section.

Other Electric Utilities’ USD adjusted earnings in 2026 are expected to be lower than 2025 due to the sale of GBPC.

In November 2025, the Government of Barbados and BLPC agreed to new Transmission, Distribution, Sales and Dispatch (“T&D”) and Generation and Energy Storage (“G&S”) licenses. On May 11, 2026, BLPC’s new licenses became effective after the repeal of the previous license. The G&S license is valid until 2047, unless otherwise extended. The T&D License is valid for 30 years.

In 2026, capital investment in the Other Electric Utilities segment is expected to be approximately $80 million USD (2025 – $67 million USD), including AFUDC, primarily in projects to support system reliability.

Other

The adjusted net loss from the Other segment is expected to be consistent with 2025. Higher contributions from EES, as discussed below, are expected to be offset by higher Corporate OM&G and interest expense.

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 million USD to $30 million USD. However, in light of strong market conditions in Q1 2026, EES expects adjusted net income for 2026 to be $60 million USD to $80 million USD.

In 2026, capital investment in the Other segment is expected to be approximately $10 million (2025 – $6 million).

CONSOLIDATED BALANCE SHEET HIGHLIGHTS

Significant changes in the Consolidated Balance Sheets between December 31, 2025 and June 30, 2026 include:


millions of dollars	Total Increase (Decrease)		Explanation of Increase (Decrease)
Assets
Derivative instruments (current and long-term)	$	71	Increased due to new contracts and changes in existing positions at EES, and higher balance on FX hedges at Corporate
Regulatory assets (current and long- term)		(100)	Decreased due to lower storm costs recovery assets at TEC, and the sale of GBPC. These were partially offset by increased deferred income tax regulatory asset and deferrals related to the fuel adjustment mechanism (“FAM”) at NSPI, and the effect of FX translation of Emera’s non-Canadian affiliates
Property, plant and equipment (“PP&E”), net of accumulated depreciation and amortization	1,541		Increased due to capital additions in excess of depreciation and the effect of FX translation of Emera’s non-Canadian affiliates, partially offset by the sale of GBPC
Goodwill		205	Increased 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)	$	656	Increased due to issuance of long-term debt at Emera US Finance, LLC (“Emera Finance”) and PGS, higher utilization of committed credit facilities at Corporate, and the effect of FX translation of Emera’s non-Canadian affiliates. These were partially offset by repayment of long-term debt at Emera US Finance LP (“Emera US Finance”), and the sale of GBPC
Accounts payable	(258)		Decreased due to lower commodity prices at EES, timing of accounts payable at NSPI and the sale of GBPC. These were partially offset by timing of property taxes payable at TEC and the effect of FX translation of Emera’s non-Canadian affiliates
Deferred income tax liabilities, net of deferred income tax assets		169	Increased due to tax deductions in excess of accounting depreciation related to PP&E, and the effect of FX translation of Emera’s non-Canadian affiliates. These were partially offset by a decrease in net regulatory assets, and increased tax credits at TEC
Regulatory liabilities (current and long-term)	75		Increased due to the effect of FX translation of Emera’s non-Canadian affiliates, and higher storm reserve regulatory liability at TEC
Other liabilities (current and long-term)		105	Increased due to timing of interest payments at Corporate, timing of sales tax payments at EES, and the effect of FX translation of Emera’s non-Canadian affiliates
Common stock	363		Increased due to shares issued
Accumulated other comprehensive income		407	Increased due to the effect of FX translation of Emera’s non-Canadian affiliates
Retained earnings		221	Increased due to net income in excess of dividends paid

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

OTHER DEVELOPMENTS

Sale of GBPC

On May 12, 2026, Emera completed the sale of its 100 per cent interest in GBPC. As a result of the sale, Emera recognized a loss of $21 million after transaction costs ($19 million, after tax and transaction costs, or $0.06 per common share). This was recorded in “Other (expense) income, net” on the Condensed Consolidated Statements of Income and included in the “Other Electric Utilities” and “Other” segments.

Canadian Tax Legislation Changes

On March 26, 2026, Bill C-15, an Act to implement certain provisions of the 2025 budget tabled in Parliament on November 4, 2025, was enacted. Bill C-15, among other measures, reinstates the Accelerated Investment Incentive (“AII”) and introduces the Clean Electricity Investment Tax Credit (“CEITC”). The AII provides enhanced first-year capital cost allowance deductions, while the CEITC is a refundable tax credit of 15 per cent, which is reduced to 5 per cent if prescribed labour requirements are not met, on eligible property, including interprovincial and territorial transmission assets and qualifying refurbishments on eligible property. The enactment of Bill C-15 did not have a material impact on the Company year-to-date in 2026. The Company continues to assess potential future impacts of the legislation.

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. On July 30, 2026, the NMPRC issued a final order approving the transaction. On July 31, 2026, certain of the intervening parties filed a notice of appeal of the final order to the New Mexico Supreme Court. There have been no further steps taken in the appeal process to date. The transaction is expected to close in August 2026.

As a result of the pending sale, NMGC’s assets and liabilities were classified as held for sale beginning Q3 2024 and the carrying value of the assets and liabilities were adjusted to FV less cost to sell. At each reporting date, the Company performs an assessment of the FV of the disposal group by comparing the FV of expected transaction proceeds, less costs to sell, to the carrying value of net assets, including goodwill. There were no impairment or FV less costs to sell adjustments recorded in 2026.

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 $134 million ($97 million USD) was recorded on these assets from August 5, 2024, the date they were classified as held for sale, through June 30, 2026. Of the $134 million ($97 million USD) recorded to date, $37 million ($27 million USD) was recorded in 2026.

Cybersecurity Incident

On April 25, 2025, Emera and NSPI discovered a cybersecurity incident involving unauthorized access into certain parts of its Canadian IT network and servers supporting portions of its business applications (the “Cybersecurity Incident’). There was no disruption to the Canadian physical operations or Emera’s US or Caribbean utilities’ operations.

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 substantially complete. 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 in the Company’s 2025 annual MD&A.

FINANCIAL HIGHLIGHTS

Florida Electric Utility


For the	Three months ended June 30				Six months ended June 30
millions of USD (except as indicated)	2026		2025		2026		2025
Operating revenues – regulated electric	$	862	$	839	$	1,664	$	1,488
Regulated fuel for generation and purchased power	$	181	$	188	$	395	$	349
Contribution to consolidated net income	$	189	$	188	$	320	$	302
Contribution to consolidated net income – CAD	$	261	$	260	$	441	$	424
Electric sales volumes (Gigawatt hours (“GWh”))		5,341		5,400		10,052		10,036
Electric production volumes (GWh)		5,943		5,925		10,698		10,561
Average fuel cost in dollars per megawatt hour (“MWh”)	$	30	$	32	$	37	$	33

The impact of the change in FX rates was minimal for the three months ended June 30, 2026, and decreased CAD earnings for the six months ended June 30, 2026, by $8 million.

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 – 2025	$	188	$	302
Increased operating revenues due to new base rates and customer growth. Year-over-year also increased due to storm cost recovery revenue (offset in OM&G) and increased off-system sales		23		176
Decreased fuel for generation and purchased power quarter-over-quarter due to a decrease in purchased power resulting from the timing of production outages and lower natural gas prices. Year-over-year increase due to higher natural gas prices		7		(46)
Increased OM&G year-over-year due to higher storm cost recognition (offset in revenue) and timing of production outage costs, partially offset by decreased regulatory deferrals		(1)		(52)
Increased depreciation and amortization due to increased PP&E placed in service		(13)		(25)
Increased interest expense due to higher debt balances		(7)		(14)
Increased state and municipal taxes due to higher revenues		(6)		(15)
Other		(2)		(6)
Contribution to consolidated net income – 2026	$	189	$	320

Canadian Electric Utilities


	Three months ended				Six months ended
For the	June 30				June 30
millions of dollars (except as indicated)	2026		2025		2026		2025
Operating revenues – regulated electric	$	448	$	436	$	1,060	$	1,035
Regulated fuel for generation and purchased power (1)	$	226	$	215	$	543	$	574
Contribution to consolidated net income	$	16	$	17	$	102	$	138
Electric sales volumes (GWh)		2,506		2,373		5,933		5,706
Electric production volumes (GWh)		2,615		2,497		6,333		6,086
Average fuel costs in dollars per MWh	$	86	$	86	$	86	$	94

(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	2026		2025		2026		2025
NSPI	$	6	$	6	$	80	$	116
Equity investment in NSPML		10		11		22		22
Contribution to consolidated net income	$	16	$	17	$	102	$	138

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 – 2025	$	17	$	138
Increased operating revenues at NSPI due to higher commercial and industrial sales volumes and favourable weather, partially offset by changes in electricity pricing effective January 1, 2026 and May 1, 2026. In addition, residential sales volumes decreased operating revenues quarter-over-quarter and increased operating revenues year-over-year		12		25
Increased regulated fuel for generation and purchased power at NSPI quarter-over-quarter due to higher commodity prices and increased sales volumes, partially offset by decreased Nova Scotia output-based pricing system (“OBPS”) carbon tax. Decreased regulated fuel for generation and purchased power at NSPI year-over-year due to decreased Nova Scotia OBPS carbon tax, partially offset by increased sales volumes.		(11)		31
Decreased FAM deferral at NSPI year-over-year primarily due to lower under-recovery of fuel costs		(2)		(57)
Increased OM&G at NSPI year-over-year due to higher storm restoration costs, lower administrative overhead allocated to PP&E, and higher costs for transmission and distribution operations. These were partially offset by lower costs year-over-year related to the Cybersecurity Incident and recovery of deferred storm costs		-		(9)
Increased depreciation and amortization at NSPI due to increased PP&E placed in service		(1)		(7)
Decreased income tax recovery year-over-year as a result of higher clean technology investment tax credits in 2025 at NSPI		(2)		(19)
Other		3		-
Contribution to consolidated net income – 2026	$	16	$	102

Gas Utilities and Infrastructure

On August 5, 2024, Emera announced an agreement to sell NMGC. On July 30, 2026, the NMPRC issued a final order approving the transaction, which is expected to close in August 2026. For more information on the pending transaction, refer to the “Other Developments” section.


	Three months ended				Six months ended
For the	June 30				June 30
millions of USD (except as indicated)	2026		2025		2026		2025
Operating revenues – regulated gas (1)	$	270	$	256	$	688	$	681
Operating revenues – non-regulated		4		4		8		8
Total operating revenue	$	274	$	260	$	696	$	689
Regulated cost of natural gas	$	43	$	53	$	156	$	206
Contribution to consolidated net income	$	39	$	35	$	138	$	118
Contribution to consolidated net income – CAD	$	55	$	48	$	191	$	168
Gas sales volumes (millions of Therms)		733		759		1,592		1,616

(1) Operating revenues – regulated gas includes $11 million of finance income from Brunswick Pipeline (2025 – $11 million) for the three months ended June 30, 2026 and $22 million (2025 – $23 million) for the six months ended June 30, 2026.

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	2026		2025		2026		2025
PGS	$	36	$	25	$	91	$	65
NMGC		(6)		2		29		36
Other		9		8		18		17
Contribution to consolidated net income	$	39	$	35	$	138	$	118

The impact of the change in FX rates was minimal for the three months ended June 30, 2026, and decreased CAD earnings for the six months ended June 30, 2026 by $6 million.

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 – 2025	$	35	$	118
Increased gas revenues due to increased rates and higher-off system sales at PGS, partially offset by lower fuel revenue at NMGC		14		7
Decreased cost of natural gas due to lower natural gas prices at NMGC. Year-over-year partially offset by higher natural gas prices at PGS		10		50
Increased OM&G, primarily due to higher labour and benefit costs at NMGC and PGS		(12)		(15)
Increased depreciation primarily due to PP&E placed in service at PGS and NMGC		(3)		(7)
Increased income tax expense primarily due to increased income before provision for income taxes at PGS		(2)		(8)
Other		(3)		(7)
Contribution to consolidated net income – 2026	$	39	$	138

Other Electric Utilities

On May 12, 2026, Emera completed the sale of GBPC. For further details, refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.

	$			$		$			$
	Three months ended					Six months ended
For the	June 30					June 30
millions of USD (except as indicated)	2026			2025		2026			2025
Operating revenues – regulated electric	$	97		$	104	$	189		$	196
Regulated fuel for generation and purchased power	$	57		$	53	$	101		$	100
Contribution to consolidated adjusted net income	$	3		$	9	$	10		$	9
Loss on sale of GBPC		(12	)		-		(12	)		-
Equity securities MTM gain		1			1		-			1
Contribution to consolidated net income	$	(8	)	$	10	$	(2	)	$	10
Contribution to consolidated adjusted net income – CAD	$	5		$	12	$	13		$	12
Contribution to consolidated net income – CAD	$	(10	)	$	14	$	(3	)	$	14
Electric sales volumes (GWh)		290			325		596			628
Electric production volumes (GWh)		313			346		639			668
Average fuel costs in dollars per MWh	$	182		$	153	$	158		$	150

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	2026		2025		2026		2025
BLPC	$	3	$	4	$	8	$	6
GBPC		(1)		5		1		3
Other		1		-		1		-
Contribution to consolidated adjusted net income	$	3	$	9	$	10	$	9

The impact of the change in FX rates on CAD earnings for the three and six months ended June 30, 2026 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 – 2025	$	10	$	10
Decreased operating revenues – regulated electric due to sale of GBPC in Q2 2026, partially offset by higher fuel revenue at BLPC as a result of higher fuel prices		(7)		(7)
Increased regulated fuel for generation and purchased power due to higher fuel costs at BLPC, partially offset by the sale of GBPC		(4)		(1)
Decreased OM&G due to sale of GBPC		4		5
Loss on sale of GBPC		(12)		(12)
Other		1		3
Contribution to consolidated net income – 2026	$	(8)	$	(2)

Other


	Three months ended				Six months ended
For the	June 30				June 30
millions of dollars	2026		2025		2026		2025
Marketing and trading margin (1)(2)	$	(28)	$	(19)	$	155	$	101
Other non-regulated operating revenue		8		7		22		16
Total operating revenues – non-regulated	$	(20)	$	(12)	$	177	$	117
Contribution to consolidated adjusted net (loss) income	$	(125)	$	(101)	$	(120)	$	(127)
MTM (loss) gain, after-tax (3)		(89)		(31)		59		173
Loss on sale of GBPC, after tax and transaction costs (4)		(3)		-		(3)		-
Charges related to the pending sale of NMGC, after-tax (5)		-		(72)		-		(72)
Contribution to consolidated net (loss) income	$	(217)	$	(204)	$	(64)	$	(26)

(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 $104 million for the three months ended June 30, 2026 (2025 – $91 million loss) and a gain of $107 million for the six months ended June 30, 2026 (2025 – $197 million gain).

(3) Net of income tax recovery of $37 million for the three months ended June 30, 2026 (2025 – $13 million recovery) and $24 million income tax expense for the six months ended June 30, 2026 (2025 – $71 million expense).

(4) Net of income tax recovery of $2 million for the three and six months ended June 30, 2026.

(5) 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.

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	2026		2025		2026		2025
Emera Energy
EES	$	(24)	$	(14)	$	81	$	55
Other		9		(3)		11		(4)
Corporate – see breakdown of contribution below		(110)		(84)		(212)		(178)
Contribution to consolidated adjusted net (loss) income	$	(125)	$	(101)	$	(120)	$	(127)

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 – 2025	$	(204)	$	(26)
Decreased marketing and trading margin quarter-over-quarter due to timing of hedge settlements related to EES’ storage positions and higher transport costs. Increased marketing and trading margin year-over-year due to favourable weather conditions in Q1 that led to higher natural gas prices and increased volatility that created profitable opportunities		(9)		54
Increased OM&G at Corporate primarily due to a lower gain on the long-term incentive hedge and increased costs as a result of the NYSE listing		(1)		(13)
Increased equity earnings at Bear Swamp due to business interruption insurance received related to an unplanned outage in 2025 and higher generation		19		23
Increased Corporate FX losses on the translation of USD short-term debt balances. Year-over-year is partially offset by a decreased realized loss on FX hedges		(9)		(4)
Increased interest expense due to higher long-term debt resulting from the timing of financings, partially offset by interest earned on debt proceeds held in invested cash. Year-over-year is also partially offset by lower short-term debt		(21)		(28)
Decreased income tax recovery quarter-over-quarter due to an unfavourable impact of foreign currency translation. Decreased income tax recovery year-over-year due to decreased loss before provision for income taxes and an unfavourable impact of foreign currency translation		(3)		(15)
Unfavourable changes in MTM, after-tax, due to a loss on Corporate FX hedges compared to gain in prior year and amortization of gas transportation assets and changes in existing positions at EES		(58)		(114)
Charges related to the pending sale of NMGC, after-tax		72		72
Other		(3)		(13)
Contribution to consolidated net (loss) income – 2026	$	(217)	$	(64)

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	2026		2025		2026		2025
Operating expenses (1)	$	(22)	$	(20)	$	(41)	$	(27)
Interest expense		(112)		(91)		(215)		(187)
Income tax recovery		43		40		83		74
Preferred dividends		(19)		(19)		(39)		(37)
Other (2)(3)		-		6		-		(1)
Corporate adjusted net loss (4)(5)(6)	$	(110)	$	(84)	$	(212)	$	(178)

(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 $1 million ($1 million after-tax) for the three months ended June 30, 2026 (2025 – $2 million net loss, pre-tax and $2 million loss, after-tax) and a $1 million net loss, pre-tax ($1 million after-tax) for the six months ended June 30, 2026 (2025 – $10 million net loss, pre-tax and $7 million loss, after-tax) on FX hedges, as discussed above.

(4) Excludes a MTM loss, after-tax, of $12 million for the three months ended June 30, 2026 (2025 – $30 million gain, after-tax) and a MTM loss, after-tax of $17 million for the six months ended June 30, 2026 (2025 – $33 million gain, after-tax).

(5) 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.

(6) Excludes loss on the sale of GBPC of $5 million ($3 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 2026 through 2030 period to support 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 and 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 securities and issuance of common equity through Emera’s DRIP and ATM programs.

Emera has total committed credit facilities with varying maturities that cumulatively provide $3.3 billion CAD and $2.1 billion USD of credit, with approximately $1.0 billion CAD and $1.0 billion USD undrawn and available at June 30, 2026. The Company was holding a cash balance of $400 million, which includes $4 million classified as assets held for sale, related to the pending sale of NMGC, at June 30, 2026. 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, 2026 and 2025 include:

	$		$		$
millions of dollars	2026		2025		Change
Cash, cash equivalents, restricted cash, and cash associated with assets held for sale, beginning of period	$	371	$	221	$	150
Provided by (used in):
Operating cash flow before changes in working capital		1,411		1,306		105
Changes in non-cash working capital		(9)		(507)		498
Operating activities	$	1,402	$	799	$	603
Investing activities		(1,531)		(1,672)		141
Financing activities		95		877		(782)
Effect of exchange rate changes on cash, cash equivalents, restricted cash, and cash associated with assets held for sale		74		(7)		81
Cash, cash equivalents, restricted cash and cash associated with assets held for sale, end of period	$	411	$	218	$	193

Cash Flow from Operating Activities

Net cash provided by operating activities increased $603 million to $1,402 million for the six months ended June 30, 2026, compared to $799 million for the same period in 2025.

Cash from operations before changes in working capital increased $105 million year-over-year. This increase was due to lower fuel under-recoveries and higher storm cost recoveries at TEC, and higher marketing and trading margin at EES. These were partially offset by higher Corporate costs, lower current income tax recovery at NSPI as a result of higher clean energy technology investment tax credits in 2025 and a purchased gas adjustment refund to customers at NMGC.

Changes in non-cash working capital increased operating cash flow by $498 million year-over-year. This increase was due to favourable changes in accounts payable at TEC due to timing of storm invoice payments, timing of settlements and favourable changes in posted margin at EES, timing of Corporate interest payments and favourable changes in accounts receivable at NSPI. These were partially offset by unfavourable changes in accounts payable due to timing and unfavourable changes in fuel inventory due to increased purchases at NSPI, and unfavourable changes in accounts receivable at PGS due to new base rates.

Cash Flow from Investing Activities

Net cash used in investing activities decreased $141 million to $1,531 million for the six months ended June 30, 2026, compared to $1,672 million for the same period in 2025. The decrease was due to proceeds from sale of GBPC, partially offset by higher capital investment and lower proceeds from disposal of assets.

Capital investments, including AFUDC, for the six months ended June 30, 2026, were $1,781 million, compared to $1,757 million for the same period in 2025. Details of the 2026 capital investment by segment are shown below:

•

$1,142 million – Florida Electric Utility (2025 – $1,108 million);

•

$265 million – Canadian Electric Utilities (2025 – $319 million);

•

$340 million – Gas Utilities and Infrastructure (2025 – $288 million);

•

$30 million – Other Electric Utilities (2025 – $41 million); and

•

$4 million – Other (2025 – $1 million).

Cash Flow from Financing Activities

Net cash provided by financing activities decreased $782 million to $95 million for the six months ended June 30, 2026, compared to $877 million for the same period in 2025. This decrease was due to the retirement of Corporate long-term debt, lower issuances of long-term debt at TEC and lower net proceeds from committed facilities and short-term debt at NSPI. These were partially offset by higher proceeds from long-term debt and short-term debt at Corporate, higher net borrowing on committed credit facilities at TEC, higher net issuances of long-term debt at NSPI, higher proceeds from long-term debt at PGS and higher issuance of common shares.

Contractual Obligations

As at June 30, 2026, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:


millions of dollars	2026		2027		2028		2029		2030		Thereafter		Total
Long-term debt principal (1)(2)	$	22	$	67	$	722	$	2,034	$	512	$	17,256	$	20,613
Interest payment obligations (3)(4)		519		1,021		1,003		935		888		12,130		16,496
Purchased power (5)		206		432		413		461		454		6,423		8,389
Transportation (6)(7)		576		739		557		473		407		3,104		5,856
Fuel, gas supply and storage (8)		388		322		151		198		81		58		1,198
Capital projects		249		88		45		1		9		-		392
Pension and post-retirement obligations (9)		14		29		29		28		25		246		371
Asset retirement obligations		5		1		2		1		1		748		758
Other		94		97		186		61		49		323		810
	$	2,073	$	2,796	$	3,108	$	4,192	$	2,426	$	40,288	$	54,883

As detailed below, contractual obligations at June 30, 2026 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 $786 million related to NMGC in thereafter.

(2) The Company has hybrid notes that mature in 2054, 2056, and 2076. These maturity dates have been used in the computation of the Company’s long-term debt principal and interest payment obligations at June 30, 2026. The Company has the option to repay such notes in advance of maturity upon exercise of the Company’s redemption rights in accordance with terms of the applicable indenture.

(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, 2026, including any expected required payment under associated swap agreements.

(4) Includes $393 million related to NMGC (2026: $14 million, 2027: $34 million, 2028: $34 million, 2029: $34 million, 2030: $34 million, and $243 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 $121 million related to a gas transportation contract between PGS and SeaCoast through 2040, and $20 million of future performance obligations related to asset management agreements between PGS and EES through 2030.

(7) Includes $167 million related to NMGC (2026: $15 million, 2027: $35 million, 2028: $32 million, 2029: $22 million, 2030: $21 million, and $42 million thereafter).

(8) Includes $284 million related to NMGC (2026: $54 million, 2027: $102 million, 2028: $45 million, 2029: $42 million, and 2030: $41 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. On May 11, 2026, the NSEB issued its decision on NSPML’s 2026 assessment application, approving the collection of up to $198 million from NSPI for recovery of costs associated with the Maritime Link in 2026, subject to a monthly holdback of up to $4 million. 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 (“NLH”) 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, 2026.


millions of dollars in currency as noted below	Maturity		Credit Facilities		Utilized		Undrawn and Available
In CAD:
Emera – committed revolving credit facility		June 2031	$	1,300	$	627	$	673
NSPI – committed revolving credit facility		June 2031		800		430		370
NSPI – non-revolving facility		May 2027		500		500		-
Emera – non-revolving facility		June 2027		500		500		-
Emera – non-revolving facility		February 2027		200		200		-
In USD:
TEC – committed revolving credit facility		November 2030		1,200		802		398
TECO Finance – committed revolving credit facility		November 2030		400		30		370
PGS – committed revolving facility		November 2030		250		90		160
NMGC – revolving credit facility (1)		December 2027		125		19		106
NMGC – committed non-revolving facility (1)		October 2026		70		70		-
Other – committed revolving credit facilities		Various		8		-		8

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

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, 2026.

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

Canadian Electric Utilities

On July 14, 2026, the holders of NSPI’s $40 million senior unsecured notes exercised their option to extend the maturity date from August 14, 2026, to August 14, 2056.

On June 19, 2026, NSPI amended its $800 million revolving credit facility to extend the maturity date from June 24, 2029, to June 19, 2031. There were no other material changes in commitment amount, maturity, or interest from the prior agreement.

On May 1, 2026, NSPI amended its $500 million non-revolving facility to extend the maturity date from May 21, 2026, to May 21, 2027. There were no other material changes in commercial terms from the prior agreement.

On April 17, 2026, NSPI issued $300 million in unsecured notes that bear interest at 3.95 per cent with a maturity date of April 17, 2031. Proceeds from this issuance have been used for general corporate purposes, including repayment of existing debt.

Gas Utilities and Infrastructure

On June 30, 2026, NMGC executed an agreement to issue $140 million USD in senior unsecured notes. The agreement included $70 million USD senior unsecured notes that bear interest at 5.35 per cent with a maturity date of July 28, 2031, and $70 million USD senior unsecured notes that bear interest at 5.73 per cent with a maturity date of October 20, 2036. Proceeds from the notes due in 2031 were received on July 28, 2026, and were used for the repayment of maturing long-term debt. Proceeds from notes due in 2036 will be received on October 20, 2026, and will be used for the repayment of short-term debt outstanding. Therefore, $140 million USD of short-term debt was classified as long-term liabilities associated with held for sale as of June 30, 2026.

On May 5, 2026, PGS executed an agreement to issue $200 million USD in senior notes. The agreement included $50 million USD senior notes (“Series A”) that bear interest at 4.91 per cent with a maturity date of May 5, 2031, $100 million USD senior notes (“Series B”) that bear interest at 5.39 per cent with a maturity date of May 5, 2036, and $50 million USD senior notes (“Series C”) that bear interest at 5.64 per cent with a maturity date of August 20, 2041. Proceeds from Series A and Series B were used for the repayment of short-term debt outstanding. Proceeds from Series C will be received on August 20, 2026, and will be used for general corporate purposes, including repayment of existing debt.

Other Electric Utilities

On March 18, 2026, BLPC amended its $10 million USD note to extend the maturity date from March 2026 to May 2031, reduced the interest rate from 2.05 per cent to 1.90 per cent, and change the principal payment from $0.25 million USD quarterly to $0.5 million USD semi-annually.

On February 9, 2026, BLPC entered into a $46 million USD non-revolving facility which matures in 2031 and bears interest at 1.80 per cent. As of June 30, 2026, BLPC has drawn $44 million USD on the facility.

Other

On June 19, 2026, Emera amended its $1.3 billion revolving credit facility to extend the maturity date from June 24, 2029, to June 19, 2031. There were no other material changes in commercial terms from the prior agreement.

On June 4, 2026, Emera entered into a $500 million non-revolving facility which matures on June 4, 2027. The credit agreement contains customary representations and warranties, events of default and financial and other covenants. The non-revolving facility’s interest rates are referenced to the Term CORRA or prime rate, plus a margin. Proceeds from this facility were used for repayment of existing debt and general corporate purposes.

On March 4, 2026, EUSHI Finance Inc. (“EUSHI Finance”), Emera Finance, Emera US Holdings Inc. (“EUSHI”) and Emera filed a new shelf registration statement on Form F-10 and Form F-3 (“Registration Statement”), with the Nova Scotia Securities Commission (“NSSC”) and the US Securities and Exchange Commission (“SEC”) under the US/Canada Multijurisdictional Disclosure System. The Registration Statement was filed in connection with the prospective offer and issue by EUSHI Finance or Emera Finance of one or more series of senior and/or subordinated unsecured debt securities (“Debt Securities”), in an aggregate principal amount of up to $2.25 billion USD, during the 25-month period that the short form base shelf prospectus contained in the Registration Statement (“Base Shelf Prospectus”), including any further amendments thereto, remains valid. The Debt Securities may be offered in one or more transactions, at prices, with maturities and on terms to be set forth in one or more prospectus supplements to be filed with the NSSC and the SEC at the time of any such offering.

On March 23, 2026, Emera Finance completed an issuance of $750 million USD aggregate principal amount of fixed-to-fixed reset rate junior subordinated notes, pursuant to the prospectus supplement, dated March 23, 2026, to the Base Shelf Prospectus. The issuance consisted of $375 million USD aggregate principal amount of 6.65 per cent Series A fixed-to-fixed reset rate junior subordinated notes due 2056 and $375 million USD aggregate principal amount of 6.85 per cent Series B fixed-to-fixed reset rate junior subordinated notes due 2056 (collectively, the “Notes”). The Notes are fully and unconditionally guaranteed, on a joint, several and subordinated basis, by Emera and EUSHI.

On March 27, 2026, Emera Finance completed an issuance of $750 million USD aggregate principal amount of senior notes pursuant to the prospectus supplement, dated March 27, 2026, to the Base Shelf Prospectus. The issuance consisted of $450 million USD aggregate principal amount of senior notes that bear interest at a rate of 4.50 per cent with a maturity date of April 1, 2029 and $300 million USD aggregate principal amount of senior notes that bear interest at a rate of 5.20 per cent with a maturity date of April 1, 2033. The senior notes are fully and unconditionally guaranteed, on a joint and several basis, by Emera and EUSHI.

Together these issuances were used to redeem all $1.2 billion USD of Emera’s outstanding 6.75 per cent fixed-to-floating subordinated notes - Series 2016-A due 2076, and to repay Emera US Finance’s $750 million USD 3.55 per cent senior unsecured note on June 15, 2026, upon maturity.

On February 20, 2026, Emera amended its $200 million unsecured non-revolving facility to extend the maturity date from February 20, 2026 to February 19, 2027. 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 2025 annual MD&A, with material updates noted below:

On May 20, 2026, Moody’s Ratings revised its outlook on Emera and TEC 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 2025

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

The Company has standby letters of credit and surety bonds in the amount of $174 million USD (December 31, 2025 – $271 million USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed annually, as required.

Emera, on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The expiry date of this letter of credit was extended to June 2027. The amount committed as at June 30, 2026 was $72 million (December 31, 2025 – $70 million).

Emera’s guarantee of $66 million USD relating to outstanding notes of ECI was automatically terminated in Q2 2026, and no obligations remain outstanding.

Outstanding Stock Data

Common Stock


	millions of		millions of
Issued and outstanding:	shares		dollars
Balance, December 31, 2025		301.76	$	9,387
Issuance of common stock under ATM program (1)		2.66		184
Issued under the DRIP, net of discounts		2.08		141
Senior management stock options exercised and Employee Share Purchase Plan		0.65		38
Balance, June 30, 2026		307.15	$	9,750

(1) For the three months ended June 30, 2026, no common shares were issued under Emera’s ATM program. For the six months ended June 30, 2026, a total of 2,657,496 common shares were issued under Emera’s ATM program at an average price of $69.89 per share for gross proceeds of $186 million ($184 million, net of after-tax issuance costs). As at June 30, 2026, an aggregate gross sales limit of $414 million remained available for issuance under the ATM program.

As at August 5, 2026, the amount of issued and outstanding common shares was 307.2 million.

If all outstanding stock options were converted as at August 5, 2026, an additional 4.3 million common shares would be issued and outstanding.

Preferred Stock

As at August 5, 2026, Emera had the following preferred shares issued and outstanding: Series A – 6.0 million; Series C – 10.0 million; Series E – 5.0 million; Series F – 8.0 million; Series H – 12.0 million; Series J – 8.0 million, and Series L – 9.0 million. Emera’s preferred shares do not have voting rights unless the Company fails to pay, in aggregate, eight quarterly dividends.

On April 9, 2026, Emera announced that it would not redeem the currently outstanding Cumulative Minimum Rate Reset First Preferred Shares, Series J (“Series J Shares”) on May 15, 2026 (the “Conversion Date”).

On April 15, 2026, Emera announced a dividend rate of 6.345 per cent per annum on the Series J Shares during the five-year period commencing on May 15, 2026, and ending on (and inclusive of) May 14, 2031. Emera also announced a dividend rate of 5.598 per cent on the Cumulative Floating Rate First Series K Shares (“Series K Shares”) for the three-month period commencing on May 15, 2026, and ending on (inclusive of) August 14, 2026.

During the conversion period between April 15, 2026, and April 30, 2026, the holders of Series J Shares had the right, at their option, to convert all or any of their Series J Shares, on a one-for-one basis, into Series K Shares. On May 5, 2026, Emera announced that after having taken into account all conversion notices received from holders of its outstanding Series J Shares by the April 30, 2026 deadline for conversion notices, less than the 1,000,000 Series J Shares required to give effect to conversions into Series K Shares were tendered for conversion. As a result, in accordance with certain rights, privileges, restrictions and conditions attaching to the Series J Shares, none of Emera’s outstanding Series J Shares were converted into Series K Shares on May 15, 2026. On the Conversion Date there was 8.0 million Series J Shares outstanding.

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 $60 million for the three months ended June 30, 2026 (2025 – $42 million) and $100 million for the six months ended June 30, 2026 (2025 – $91 million). NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments. For further details, refer to the “Contractual Obligations” section.

•

Natural gas transportation capacity purchases from M&NP are reported in the Condensed Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues – non-regulated, totalled $3 million for the three months ended June 30, 2026 (2025 – $3 million) and $10 million for the six months ended June 30, 2026 (2025 – $11 million).

As at June 30, 2026, Emera and its associated companies had $69 million due from related parties (December 31, 2025 – $35 million) recorded in “Receivables and other current assets”, and $35 million due to related parties (December 31, 2025 – $32 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 2025 annual MD&A.

Derivative Assets and Liabilities Recognized on the Balance Sheet

	$		$
As at	June 30		December 31
millions of dollars	2026		2025
Regulatory Deferral:
Derivative instrument assets (1)	$	53	$	24
Derivative instrument liabilities (2)		(14)		(34)
Regulatory assets (1)		18		36
Regulatory liabilities (2)		(36)		(25)
Net asset	$	21	$	1
HFT Derivatives:
Derivative instrument assets (1)	$	201	$	158
Derivative instrument liabilities (2)		(646)		(614)
Net liability	$	(445)	$	(456)
Other Derivatives:
Derivative instrument assets (1)	$	32	$	16
Derivative instrument liabilities (2)		(17)		(1)
Net asset	$	15	$	15

(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	2026		2025		2026		2025
Regulatory Deferral:
Regulated fuel for generation and purchased power (1)	$	(3)	$	(7)	$	4	$	(6)
HFT Derivatives:
Non-regulated operating revenues	$	39	$	(14)	$	380	$	464
Other Derivatives:
OM&G	$	10	$	5	$	32	$	25
Other (expense) income, net		(16)		41		(23)		37
Net gains (losses)	$	(6)	$	46	$	9	$	62
Total net gains	$	30	$	25	$	393	$	520

(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, 2026, the unrealized gain in Accumulated Other Comprehensive Income (“AOCI”) was $10 million, after-tax (December 31, 2025 – $10 million, after-tax). For the three and six months ended June 30, 2026, unrealized gains of $1 million ($1 million for the three and six months ended June 30, 2025, respectively) were reclassified from AOCI into interest expense, net.

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 required by Canadian and US Securities laws. The Company’s internal control framework is based on criteria published in the Internal Control - Integrated Framework (2013), 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, 2026, 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. Since that time, the Company has restored substantially all the financial systems and transitioned back from corresponding business continuity processes, which resulted in a material change in the Company’s ICFR at its Canadian affiliates during the period ended June 30, 2026. For more information on the Cybersecurity Incident, refer to the “Other Developments” section.

There were no other material changes in the Company’s ICFR during the quarter ended June 30, 2026, that have materially affected, or are reasonably likely to materially affect, the Company’s ICFR.

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 reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. There were no material changes in the nature of the Company’s critical accounting estimates from those disclosed in Emera’s 2025 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.

Accounting for Environmental Credits and Environmental Credit Obligations

In May 2026, the FASB issued ASU 2026-02, Environmental Credits and Environmental Credit Obligations (Topic 818). This ASU establishes new guidance for the recognition, measurement, presentation, and disclosure of environmental credits (such as renewable energy credits, carbon offsets, and similar instruments) and environmental credit obligations. The ASU is effective for fiscal years beginning after December 15, 2027, and interim periods within those fiscal years. Early adoption is permitted. An entity must apply the guidance retrospectively through a cumulative-effect adjustment to retained earnings. The Company is currently evaluating the impact of adoption of the standard update on its consolidated financial statements.

Accounting for Government Grants Received by Business Entities

In December 2025, the FASB issued ASU 2025-10, Government Grants (Topic 832) – Accounting for Government Grants Received by Business Entities. The ASU adds guidance to ASC 832 on the recognition, measurement, and presentation of government grants. The guidance will be effective for annual reporting periods beginning after December 15, 2028, and interim reporting periods within those annual reporting periods. Early adoption is permitted. The standard updates are to be applied using either a modified prospective, modified retrospective, or full retrospective approach, as detailed in the ASU. The Company is currently evaluating the impact of adoption of the standard update on its consolidated financial statements.

Targeted Improvements to the Accounting for Internal-Use Software

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

Disaggregation of Income Statement Expenses

In November 2024, the FASB issued ASU 2024-03, Income Statement Reporting – Comprehensive

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

SUMMARY OF QUARTERLY RESULTS


For the quarter ended millions of dollars		Q2		Q1		Q4		Q3		Q2		Q1		Q4		Q3
(except per share amounts)	2026		2026		2025		2025		2025		2025		2024		2024
Operating revenues	$	2,011	$	2,813	$	2,006	$	2,106	$	1,988	$	2,676	$	1,763	$	1,802
Net income attributable to common shareholders	$	105	$	562	$	68	$	228	$	135	$	583	$	154	$	4
EPS – basic	$	0.34	$	1.85	$	0.23	$	0.76	$	0.45	$	1.96	$	0.52	$	0.01
EPS – diluted	$	0.34	$	1.85	$	0.25	$	0.76	$	0.45	$	1.96	$	0.52	$	0.01

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 2026 compared to Q2 2025

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

Q1 2026 compared to Q1 2025

For Q1 2026 net income attributable to common shareholders, compared to Q1 2025, decreased by $21 million due to decreased MTM gains, decreased earnings at NSPI, the impact of a stronger CAD and increased Corporate costs. These were partially offset by increased earnings at EES, PGS and TEC. The change in EPS was also impacted by an increase in weighted average shares outstanding.

Q4 2025 compared to Q4 2024

For Q4 2025, net income attributable to common shareholders, compared to Q4 2024, decreased $86 million due to decreased earnings at NSPI and NMGC; increased Corporate costs; and Q4 2024 tax benefit related to a specific financing structure and its wind-up and the tax benefit related to the incremental gain on sale of Emera’s interest in the Labrador Island Link. These were partially offset by decreased MTM losses; increased earnings at EES; and Q4 2024 charges related to wind-down costs for certain asset impairments. The change in EPS was also impacted by an increase in weighted average shares outstanding.

Q3 2025 compared to Q3 2024

For Q3 2025, net income attributable to common shareholders, compared to Q3 2024, increased $224 million primarily due to charges related to the pending sale of NMGC recognized in Q3 2024; and increased earnings at TEC. These were partially offset by increased MTM losses; lower earnings at NSPI and NMGC; and higher Corporate costs. The change in EPS was also impacted by an increase in weighted average shares outstanding.