Exhibit 99.1

 

Management’s Discussion & Analysis

As at May 8, 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 first quarter of 2026 relative to the same quarter in 2025; and its financial position as at March 31, 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 months ended March 31, 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 March 31, 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”)
Grand Bahama Power Company Limited (“GBPC”)		The Grand Bahama Port Authority (“GBPA”)
Equity Investments
NSP Maritime Link Inc. (“NSPML”)		NSEB
Maritimes & Northeast Pipeline Limited Partnership and Maritimes & Northeast Pipeline, LLC (“M&NP”)		CER and FERC
St. Lucia Electricity Services Limited (“Lucelec”)		National Utility Regulatory Commission
Wasoqonatl Transmission Incorporated (“WTI”)		NSEB

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

 

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TABLE OF CONTENTS

 

 

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 timing and outcome of the pending sale of GBPC, 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.

 

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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.

 

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

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

*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 anticipated 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 effect of mark-to-market (“MTM”) from net income attributable to common shareholders. 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.

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.

 

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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 March 31
millions of dollars (except per share amounts)		2026				2025
Net income attributable to common shareholders		$	562			$	583
MTM gain, after-tax (1)			147				204
Adjusted net income		$	415			$	379
EPS – basic		$	1.85			$	1.96
Adjusted EPS – basic		$	1.37			$	1.28
(1) Net of income tax expense of $61 million for the three months ended March 31, 2026 (2025 – $84 million expense).

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.

Reconciliation of Net Income to EBITDA and Adjusted EBITDA

 

For the		Three months ended March 31
millions of dollars		2026				2025
Net income (1)		$	582			$	601
Interest expense, net			271				255
Income tax expense			129				119
Depreciation and amortization			339				319
EBITDA		$	1,321			$	1,294
MTM gain, excluding income tax			208				288
Adjusted EBITDA		$	1,113			$	1,006
(1) Net income is income before Non-controlling interest in subsidiaries and Preferred stock dividends.

CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Earnings

Earnings Impact of MTM Gain, After-Tax

MTM gain, after-tax decreased $57 million to $147 million in Q1 2026, compared to $204 million in Q1 2025, primarily due to unfavourable changes in existing positions and higher amortization of gas transportation assets at Emera Energy Services (“EES”).

 

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Consolidated Financial Highlights

 

For the		Three months ended March 31
millions of dollars			2026				2025
Florida Electric Utility		$	180			$	164
Canadian Electric Utilities			86				121
Gas Utilities and Infrastructure			136				120
Other Electric Utilities			8				-
Other			5				(26)
Adjusted net income		$	415			$	379
MTM gain, after-tax			147				204
Net income attributable to common shareholders		$	562			$	583

The following table highlights significant changes in adjusted net income from 2025 to 2026.

 

For the		Three months ended
millions of dollars		March 31
Adjusted net income – 2025		$	379
Operating Unit Performance
Increased earnings at EES due to favourable market conditions that led to higher natural gas prices and increased volatility that created profitable opportunities			36
Increased earnings at PGS due to higher revenue from new base rates and higher off-system sales, partially offset by higher income tax expense and the impact of a stronger CAD			18
Increased earnings at TEC primarily due to higher revenue from new base rates and off-system sales, partially offset by the impact of a stronger CAD and higher depreciation			16
Decreased earnings at NSPI due to lower income tax recovery as a result of higher clean technology investment tax credits in 2025 ($16 million), higher operating, maintenance and general expenses (“OM&G”), primarily reflecting higher storm restoration and power generation costs, and higher depreciation expense, partially offset by higher sales volumes			(36)
Corporate
Increased OM&G, pre-tax, primarily due to lower gain on the long-term incentive hedge and increased costs as a result of the New York Stock Exchange (“NYSE”) listing			(12)
Increased interest expense, pre-tax due to increased total debt, partially offset by lower interest rates			(7)
Increased income tax recovery primarily due to an increased loss before provision for income taxes and increased deferred income tax asset valuation allowance adjustment			6
Other Variances			15
Adjusted net income – 2026		$	415

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

 

For the		Three months ended March 31
millions of dollars		2026				2025
Operating cash flow before changes in working capital		$	775			$	733
Change in working capital			(40	)			(34)
Operating cash flow		$	735			$	699
Investing cash flow		$	(872)			$	(708)
Financing cash flow		$	2,208			$	123
For further discussion of cash flow, refer to the “Consolidated Cash Flow Highlights” section.
As at			March 31				December 31
millions of dollars			2026				2025
Total assets		$	48,062			$	44,817
Total long-term debt (including current portion) (1)		$	22,460			$	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 condensed consolidated interim financial statements.

 

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Consolidated Income Statement Highlights

 

For the		Three months ended March 31
millions of dollars (except per share amounts)		2026				2025				Variance
Operating revenues		$	2,813			$	2,676			$	137
Operating expenses			1,870				1,751				(119)
Income from operations		$	943			$	925			$	18
Other income, net		$	18			$	31			$	(13)
Income tax expense		$	129			$	119			$	(10)
Net income attributable to common shareholders		$	562			$	583			$	(21)
Adjusted net income		$	415			$	379			$	36
Weighted average shares of common stock outstanding (in millions)			303.3				297.0				6.3
EPS – basic		$	1.85			$	1.96			$	(0.11)
EPS – diluted		$	1.85			$	1.96			$	(0.11)
Adjusted EPS – basic		$	1.37			$	1.28			$	0.09
Dividends per common share declared		$	0.7325			$	0.7250			$	0.0075
Adjusted EBITDA		$	1,113			$	1,006			$	107

Operating Revenues

For Q1 2026, operating revenues increased $137 million compared to Q1 2025 and, excluding the change in MTM impacts, increased $203 million. The increase was due to higher marketing and trading margin at EES; higher storm cost recovery revenue at TEC (offset in OM&G); increased off-system sales at TEC and PGS; new base rates at TEC and PGS; and higher sales volumes at NSPI. These were partially offset by the impact of a stronger CAD, and lower fuel cost recoveries at NMGC.

Operating Expenses

For Q1 2026, operating expenses increased $119 million compared to Q1 2025. This increase was due to higher natural gas prices at TEC and PGS; increased storm cost recognition at TEC (offset in revenues); higher OM&G at Corporate primarily due to lower gain on the long-term incentive hedge and increased costs as a result of the NYSE listing; increased OM&G at NSPI primarily reflecting higher storm restoration and power generation costs; and increased depreciation expense at TEC and NSPI. These were partially offset by the impact of a stronger CAD and lower natural gas prices at NMGC.

Other Income, net

For Q1 2026, other income decreased $13 million compared to Q1 2025 due to lower unrealized FX gains at Corporate.

Income Tax Expense

For Q1 2026, income tax expense increased $10 million compared to Q1 2025 due to decreased tax credits recognized at NSPI, partially offset by increased deferred income tax asset valuation allowance adjustment, and increased tax credits recognized at TEC.

Net Income and Adjusted Net Income

For Q1 2026, the decrease in net income attributable to common shareholders, compared to Q1 2025, was unfavourably impacted by the $57 million decrease in MTM gains, after-tax. Excluding this change, adjusted net income increased $36 million, primarily due to increased earnings at EES, PGS and TEC. This was partially offset by decreased earnings at NSPI and increased Corporate costs.

 

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Earnings and Adjusted EPS – Basic

For Q1 2026, EPS – basic is lower than Q1 2025 due to the impact of lower earnings and an increase in weighted average shares outstanding.

For Q1 2026, adjusted EPS – basic was higher than Q1 2025 due to increased earnings partially offset by an increase in weighted average shares outstanding.

Effect of Foreign Currency Translation

Results of foreign operations are translated at the weighted average rate of exchange, and assets and liabilities of foreign operations are translated at period end rates. For additional details on the effects of foreign currency translation, refer to the Company’s 2025 annual MD&A.

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

 

		Three months ended March 31								Year ended December 31
		2026				2025				2025
Weighted average CAD/USD		$	1.37			$	1.44			$	1.41
Period end CAD/USD exchange rate		$	1.39			$	1.44			$	1.37
The table below includes Emera’s significant segments whose contributions to adjusted net income are recorded in USD currency:
For the						Three months ended March 31
millions of USD						2026				2025
Florida Electric Utility						$	131			$	114
Gas Utilities and Infrastructure (1)							95				79
Other Electric Utilities							7				-
Other segment (2)							25				5
Total (3)						$	258			$	198
(1) Includes USD net income from PGS, NMGC, SeaCoast and M&NP.
(2) Includes Emera Energy’s USD adjusted net income from EES, Bear Swamp, and interest expense on Emera Inc.’s USD denominated debt.
(3) Excludes a $110 million USD MTM gain, after-tax, for the three months ended March 31, 2026 (2025 – $143 million USD MTM gain, after-tax).

Strengthening of the CAD decreased net income attributable to common shareholders by $30 million and decreased adjusted net income by $17 million in Q1 2026 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.

 

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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 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 also anticipates earning below its allowed ROE range in 2026. Sales volumes are expected to be higher in 2026 than in 2025.

On April 30, 2026, the NSEB approved the general rate application (“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 is addressed through the NSEB’s established fuel adjustment mechanism (“FAM”) process. 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 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.

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

 

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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, 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. The public hearing was held in November 2025. The transaction is now expected to close in mid-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, which is now expected to close in mid-2026.

Other Electric Utilities

On May 5, 2026, Emera entered into an agreement to sell GBPC. For more information on the pending sale, refer to the “Other Developments” section.

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

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 now 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).

 

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CONSOLIDATED BALANCE SHEET HIGHLIGHTS

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

 

millions of dollars		Total Increase (Decrease)				Explanation of Increase (Decrease)
Assets
Cash and cash equivalents		$	2,108			Increased due to proceeds from issuance of long-term debt at Emera US Finance, LLC (“Emera Finance”), higher cash from operations, proceeds from common shares issued, and increased proceeds under committed credit facilities at Corporate and TECO Finance, Inc. (“TECO Finance”). These were partially offset by investment in Property, Plant and Equipment (“PP&E”) and dividends paid on common and preferred stock
Derivative instruments (current and long-term)			58			Increased due to new contracts and changes in existing positions at EES, and higher commodity prices at NSPI
Receivables and other assets (current and long-term)			167			Increased due to higher gas transportation assets and cash collateral at EES and increased trade receivables at NSPI and PGS. These were partially offset by decreased trade receivables at EES
Assets held for sale (current and long-term), net of liabilities (1)			66			Increased primarily due to lower accounts payable reflecting seasonal trends of the business and the effect of FX translation. These were partially offset by lower accounts receivable at NMGC
PP&E, net of accumulated depreciation and amortization			862			Increased due to capital additions in excess of depreciation and the effect of FX translation of Emera’s non-Canadian affiliates
Goodwill			95			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)		$	2,496			Increased due to issuance of long-term debt at Emera Finance, higher utilization of committed credit facilities at Corporate and TECO Finance, and the effect of FX translation of Emera’s non-Canadian affiliates
Accounts payable			(274)			Decreased due to lower commodity prices at EES and timing of accounts payable at NSPI
Deferred income tax liabilities, net of deferred income tax assets			196			Increased due to tax deductions in excess of accounting depreciation related to PP&E, changes in derivatives at EES, and the effect of FX translation of Emera’s non-Canadian affiliates. This was partially offset by a decrease in net regulatory assets
Other liabilities (current and long-term)			167			Increased due to timing of interest payments at Corporate and timing of sales tax payments at EES
Common stock			271			Increased due to shares issued
Accumulated other comprehensive income			196			Increased due to the effect of FX translation of Emera’s non-Canadian affiliates
Retained earnings			340			Increased due to net income in excess of dividends paid

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

 

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OTHER DEVELOPMENTS

Pending Sale of GBPC

On May 5, 2026, Emera entered into an agreement to sell its 100 per cent interest in GBPC. The transaction is expected to close by the end of May 2026. The pending sale is not expected to have a material impact on adjusted earnings.

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 for the three months ended March 31, 2026. The Company continues to assess potential future impacts of the legislation.

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 continues to progress in a planned, controlled and phased approach. For more information on the impact on internal controls over financial reporting, refer to the “Disclosure and Internal Controls” section. The Company maintains cyber insurance coverage and is working with its insurer on the claims process. At this time, the Cybersecurity Incident is not expected to have a material impact on the Company’s financial position or results of operations. For information on risks associated with cybersecurity incidents generally, refer to the “Enterprise Risk and Risk Management” section in the Company’s 2025 annual MD&A.

Pending Sale of NMGC

On August 5, 2024, Emera entered into an agreement to sell its indirect wholly-owned subsidiary NMGC for a total enterprise value of approximately $1.3 billion USD, consisting of cash proceeds and the transfer of debt and customary closing adjustments. The transaction is now expected to close in mid-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 Q1 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 $115 million ($83 million USD) was recorded on these assets from August 5, 2024, the date they were classified as held for sale, through March 31, 2026. Of the $115 million ($83 million USD) recorded to date, $18 million ($13 million USD) was recorded in 2026.

 

12

FINANCIAL HIGHLIGHTS

Florida Electric Utility

 

For the		Three months ended March 31
millions of USD (except as indicated)		2026				2025
Operating revenues – regulated electric		$	802			$	649
Regulated fuel for generation and purchased power		$	214			$	161
Contribution to consolidated net income		$	131			$	114
Contribution to consolidated net income – CAD		$	180			$	164
Electric sales volumes (Gigawatt hours (“GWh”))			4,711				4,636
Electric production volumes (GWh)			4,755				4,636
Average fuel cost in dollars per megawatt hour (“MWh”)		$	45			$	35

The impact of the change in the FX rate decreased CAD earnings by $8 million for the three months ended March 31, 2026.

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

 

For the		Three months ended
millions of USD		March 31
Contribution to consolidated net income – 2025						$	114
Increased operating revenues due to storm cost recovery revenue (offset in OM&G), new base rates, increased off-system sales, and customer growth							153
Increased fuel for generation and purchased power due to higher natural gas prices							(53	)
Increased OM&G due to higher storm cost recognition (offset in revenue), increased expenses related to solar investments and the timing of production outage costs							(51	)
Increased state and municipal taxes due to higher revenues							(9	)
Increased depreciation and amortization due to increased PP&E placed in service							(12	)
Increased interest expense due to higher debt balances							(7	)
Other							(4	)
Contribution to consolidated net income – 2026						$	131

Canadian Electric Utilities

 

For the		Three months ended March 31
millions of dollars (except as indicated)		2026				2025
Operating revenues – regulated electric		$	612			$	599
Regulated fuel for generation and purchased power (1)		$	317			$	359
Contribution to consolidated net income		$	86			$	121
Electric sales volumes (GWh)			3,427				3,333
Electric production volumes (GWh)			3,718				3,589
Average fuel costs in dollars per MWh		$	85			$	100

(1) Regulated fuel for generation and purchased power includes NSPI’s FAM deferral 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:

 

For the		Three months ended March 31
millions of dollars		2026				2025
NSPI		$	74			$	110
Equity investment in NSPML			12				11
Contribution to consolidated net income		$	86			$	121

 

13

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

 

For the		Three months ended
millions of dollars		March 31
Contribution to consolidated net income – 2025						$	121
Increased operating revenues at NSPI due to increased residential and commercial sales volumes, partially offset by decreased industrial sales volumes							13
Decreased regulated fuel for generation and purchased power at NSPI primarily due to lower commodity prices, decreased Nova Scotia output-based pricing system carbon tax, and changes in generation mix, partially offset by increased sales volumes							42
Decreased FAM deferral at NSPI primarily due to lower under-recovery of fuel costs							(55	)
Increased OM&G due to higher storm restoration costs and higher costs for power generation at NSPI							(9	)
Increased depreciation and amortization at NSPI due to increased PP&E placed in service							(6	)
Decreased income tax recovery as a result of higher clean technology investment tax credits in 2025 at NSPI							(17	)
Other							(3	)
Contribution to consolidated net income – 2026						$	86

Gas Utilities and Infrastructure

On August 5, 2024, Emera announced an agreement to sell NMGC. The public hearing was held in November 2025. The transaction is now expected to close mid-2026, subject to certain approvals, including regulatory approval by the NMPRC. For more information on the pending transaction, refer to the “Other Developments” section.

 

For the		Three months ended March 31
millions of USD (except as indicated)		2026				2025
Operating revenues – regulated gas (1)		$	418			$	425
Operating revenues – non-regulated			4				4
Total operating revenue		$	422			$	429
Regulated cost of natural gas		$	113			$	153
Contribution to consolidated net income		$	99			$	83
Contribution to consolidated net income – CAD		$	136			$	120
Gas sales volumes (millions of Therms)			859				857

(1) Operating revenues – regulated gas includes $11 million of finance income from Brunswick Pipeline for the three months ended March 31, 2026 (2025 – $12 million).

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

 

For the		Three months ended March 31
millions of USD		2026				2025
PGS		$	55			$	40
NMGC			35				34
Other			9				9
Contribution to consolidated net income		$	99			$	83

The impact of the change in the FX rate decreased CAD earnings by $6 million for the three months ended March 31, 2026.

 

14

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

 

For the		Three months ended
millions of USD		March 31
Contribution to consolidated net income – 2025						$	83
Decreased gas revenues due to lower fuel revenue at NMGC, partially offset by increased rates and higher off-system sales at PGS							(7)
Decreased cost of natural gas due to lower natural gas prices at NMGC, partially offset by higher natural gas prices at PGS							40
Increased depreciation primarily due to increased PP&E placed in service at PGS and NMGC							(4)
Increased income tax expense primarily due to increased income before provision for income taxes at PGS							(6)
Other							(7)
Contribution to consolidated net income – 2026						$	99

Other Electric Utilities

On May 5, 2026, Emera entered into an agreement to sell GBPC. For more information on the pending sale refer to the “Other Developments” section.

 

For the		Three months ended March 31
millions of USD (except as indicated)		2026				2025
Operating revenues – regulated electric		$	92			$	92
Regulated fuel for generation and purchased power		$	44			$	47
Contribution to consolidated adjusted net income		$	7			$	-
Contribution to consolidated adjusted net income – CAD		$	8			$	-
Equity securities MTM loss		$	(1)			$	-
Contribution to consolidated net income		$	6			$	-
Contribution to consolidated net income – CAD		$	7			$	-
Electric sales volumes (GWh)			306				303
Electric production volumes (GWh)			326				322
Average fuel costs in dollars per MWh			135				146

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

 

For the		Three months ended March 31
millions of USD		2026				2025
BLPC		$	5			$	2
GBPC			2				(2)
Contribution to consolidated adjusted net income		$	7			$	-

The impact of the change in the FX rate on CAD earnings for the three months ended March 31, 2026 was minimal.

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

 

For the		Three months ended
millions of USD		March 31
Contribution to consolidated net income – 2025						$	-
Decreased regulated fuel for generation and purchased power due to lower fuel costs at BLPC							3
Decreased income tax expense due to the 2025 remeasurement of deferred income tax liabilities as a result of a corporate income tax rate change at BLPC							2
Other							1
Contribution to consolidated net income – 2026						$	6

 

15

Other

 

For the		Three months ended March 31
millions of dollars			2026				2025
Marketing and trading margin (1) (2)		$	183			$	120
Other non-regulated operating revenue			14				9
Total operating revenues – non-regulated		$	197			$	129
Contribution to consolidated adjusted net income (loss)		$	5			$	(26)
MTM gain, after-tax (3)			148				204
Contribution to consolidated net income		$	153			$	178

(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 gain of $211 million for the three months ended March 31, 2026 (2025 – $288 million gain).

(3) Net of income tax expense of $61 million for the three months ended March 31, 2026 (2025 – $84 million expense).

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

 

For the		Three months ended March 31
millions of dollars			2026				2025
Emera Energy
EES		$	105			$	69
Other			2				(1)
Corporate – see breakdown below			(102)				(94)
Contribution to consolidated adjusted net income (loss)		$	5			$	(26	)

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

 

For the		Three months ended
millions of dollars		March 31
Contribution to consolidated net income – 2025			$    178
Increased marketing and trading margin at EES due to favourable market conditions that led to higher natural gas prices and increased volatility that created profitable opportunities			63
Increased OM&G at Corporate primarily due to lower gain on the long-term incentive hedge and increased costs as a result of the NYSE listing			(12)
Increased interest expense at Corporate primarily due to increased total debt, partially offset by lower interest rates			(7)
Increased income tax expense primarily due to increased income before provision for income taxes, partially offset by increased deferred income tax asset valuation allowance adjustment			(12)
Decreased MTM gain, after-tax, primarily due to unfavourable changes in existing positions and higher amortization of gas transportation assets at EES			(56)
Other			(1)
Contribution to consolidated net income – 2026			$    153

 

16

Corporate

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

 

For the		Three months ended March 31
millions of dollars		2026				2025
Operating expenses (1)		$	(19	)		$	(7	)
Interest expense			(103	)			(96	)
Income tax recovery			40				34
Preferred dividends			(20	)			(18	)
Other (2)(3)			-				(7	)
Corporate adjusted net (loss) income (4)		$	(102	)		$	(94	)

(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, pre-tax, net gain of nil on FX hedges for the three months ended March 31, 2026 (nil after-tax), as discussed above (2025 – $8 million loss, pre-tax and $5 million loss, after-tax).

(4) Excludes a MTM loss, after-tax, of $5 million for the three months ended March 31, 2026 (2025 – $3 million gain, after-tax).

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 $2.8 billion CAD and $2.1 billion USD of credit, with approximately $1.0 billion CAD and $983 million USD undrawn and available at March 31, 2026. The Company was holding a cash balance of $2.5 billion, which includes $9 million classified as assets held for sale, related to the pending sale of NMGC, at March 31, 2026. For further discussion, refer to the “Debt Management” section below.

 

17

Consolidated Cash Flow Highlights

Significant changes in the Condensed Consolidated Statements of Cash Flows between the three months ended March 31, 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			775				733				42
Changes in non-cash working capital			(40)				(34)				(6)
Operating activities		$	735			$	699			$	36
Investing activities			(872)				(708)				(164)
Financing activities			2,208				123				2,085
Effect of exchange rate changes on cash, cash equivalents, restricted cash, and cash associated with assets held for sale			37				-				37
Cash, cash equivalents, restricted cash and cash associated with assets held for sale, end of period		$	2,479			$	335			$	2,144

Cash Flow from Operating Activities

Net cash provided by operating activities increased $36 million to $735 million for the three months ended March 31, 2026, compared to $699 million for the same period in 2025.

Cash from operations before changes in working capital increased $42 million year-over-year. This increase was due to higher marketing and trading margin at EES and higher storm cost recoveries at TEC. These were partially offset by a purchased gas adjustment refund to customers at NMGC, higher fuel under-recoveries at PGS and lower current income tax recovery at NSPI as a result of higher clean energy technology investment tax credits in 2025.

Changes in non-cash working capital decreased operating cash flow by $6 million year-over-year. This decrease was due to unfavourable changes in accounts receivable at NSPI due to timing and PGS due to new base rates, and unfavourable change in posted margin at EES. These were partially offset by a favourable change in accounts payable at TEC due to timing of storm invoice payments.

Cash Flow from Investing Activities

Net cash used in investing activities increased $164 million to $872 million for the three months ended March 31, 2026, compared to $708 million for the same period in 2025. The increase was due to higher capital investment.

Capital investments, including AFUDC, for the three months ended March 31, 2026, were $891 million, compared to $742 million for the same period in 2025. Details of the 2026 capital investment by segment are shown below:

 

•

$567 million – Florida Electric Utility (2025 – $459 million);

 

•

$145 million – Canadian Electric Utilities (2025 – $122 million);

 

•

$162 million – Gas Utilities and Infrastructure (2025 – $143 million);

 

•

$16 million – Other Electric Utilities (2025 – $18 million); and

 

•

$1 million – Other (2025 – nil).

 

18

Cash Flow from Financing Activities

Net cash provided by financing activities increased $2,085 million to $2,208 million for the three months ended March 31, 2026, compared to $123 million for the same period in 2025. This increase was due to proceeds from long-term debt at Emera Finance, lower net repayments on committed credit facilities at TEC and Emera, higher issuance of common shares, and higher net proceeds from committed facilities at PGS. These were partially offset by lower issuances of long-term debt at TEC and lower net proceeds from committed credit facilities at NSPI.

Contractual Obligations

As at March 31, 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)		$	1,290			$	624			$	753			$	2,470			$	556			$	17,610			$	23,303
Interest payment obligations (3)(4)			1,013				1,084				1,070				981				915				16,878				21,941
Purchased power (5)			308				421				410				457				450				5,921				7,967
Transportation (6)(7)			736				701				536				459				396				3,049				5,877
Fuel, gas supply and storage (8)			563				288				189				195				81				61				1,377
Capital projects			261				76				47				4				-				-				388
Pension and post-retirement obligations (9)			21				29				28				28				25				243				374
Asset retirement obligations			6				1				2				1				1				452				463
Other			127				76				56				55				47				314				675
		$	4,325			$	3,300			$	3,091			$	4,650			$	2,471			$	44,528			$	62,365

As detailed below, contractual obligations at March 31, 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 $675 million related to NMGC (2026: $98 million and $577 million 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 March 31, 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. On April 30, 2026, Emera issued a notice of redemption for all $1.2 billion of its remaining outstanding 6.75 per cent fixed-to-floating subordinated notes. Refer to the “Debt Management” section below for further details.

(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 March 31, 2026, including any expected required payment under associated swap agreements.

(4) Includes $311 million related to NMGC (2026: $20 million, 2027: $22 million, 2028: $22 million, 2029: $22 million, 2030: $22 million, and $202 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 $120 million related to a gas transportation contract between PGS and SeaCoast through 2040, and $21 million of future performance obligations related to asset management agreements between PGS and EES through 2030.

(7) Includes $167 million related to NMGC (2026: $18 million, 2027: $34 million, 2028: $31 million, 2029: $22 million, 2030: $21 million, and $41 million thereafter).

(8) Includes $253 million related to NMGC (2026: $75 million, 2027: $51 million, 2028: $44 million, 2029: $41 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 December 23, 2025, NSPML received an interim order from the NSEB to collect up to $199 million from NSPI for recovery of costs associated with the Maritime Link in 2026, subject to a monthly holdback of up to $4 million. There was no holdback recorded in Q1 2026. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to NSEB approval.

 

19

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 March 31, 2026.

 

millions of dollars in currency as noted below		Maturity				Credit Facilities				Utilized				Undrawn and Available
In CAD:
Emera – committed revolving credit facility			June 2029			$	1,300			$	416			$	884
NSPI – committed revolving credit facility			June 2029				800				667				133
NSPI – non-revolving facility			May 2026				500				500				-
Emera – non-revolving facility			February 2027				200				200				-
In USD:
TEC – committed revolving credit facility			November 2030				1,200				766				434
TECO Finance – committed revolving credit facility			November 2030				400				105				295
PGS – committed revolving facility			November 2030				250				182				68
NMGC – revolving credit facility (1)			December 2027				125				6				119
NMGC – committed non-revolving facility (1)			October 2026				70				70				-
Other – committed non-revolving credit facilities			Various				46				-				46
Other – committed revolving credit facilities			Various				21				-				21

(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 March 31, 2026.

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

Canadian Electric Utilities

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 will be used for general corporate purposes, including repayment of existing debt.

Gas Utilities and Infrastructure

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. Therefore, $150 million USD of short-term debt was classified as long-term debt as of March 31, 2026. Proceeds from Series C will be received on August 20, 2026 and will be used for general corporate purposes, including repayment of existing debt.

 

20

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, reduce 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 March 31, 2026, BLPC has not drawn on this facility. 

Other

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. Proceeds from this issuance will be used for general corporate purposes, including repayment of existing debt.

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. Proceeds from this issuance will be used for general corporate purposes, including repayment of existing debt.

On April 30, 2026, Emera issued a notice of redemption for all $1.2 billion of its remaining outstanding 6.75 per cent fixed-to-floating subordinated notes – Series 2016-A due 2076 (the “2016 Notes”). The redemption date is June 15, 2026, and the redemption price for the 2016 Notes is 100 per cent of the principal amount of the 2016 Notes together with accrued and unpaid interest to, but excluding, the redemption date.

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.

 

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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 $224 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.

Outstanding Stock Data

Common Stock

 

Issued and outstanding:		millions of shares				millions of 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			1.08				71
Senior management stock options exercised and Employee Share Purchase Plan			0.28				16
Balance, March 31, 2026			305.78			$	9,658

(1) For the three months ended March 31, 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 March 31, 2026, an aggregate gross sales limit of $414 million remained available for issuance under the ATM program.

As at May 6, 2026 the amount of issued and outstanding common shares was 305.9 million.

If all outstanding stock options were converted as at May 6, 2026, an additional 4.5 million common shares would be issued and outstanding.

Preferred Stock

As at May 6, 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 will be converted into Series K Shares on May 15, 2026. On the Conversion Date there will continue to be 8.0 million Series J Shares outstanding.

 

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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 $40 million for the three months ended March 31, 2026 (2025 – $49 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.

 

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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 $7 million for the three months ended March 31, 2026 (2025 – $8 million).

As at March 31, 2026, Emera and its associated companies had $66 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 millions of dollars		March 31 2026				December 31 2025
Regulatory Deferral:
Derivative instrument assets (1)		$	46			$	24
Derivative instrument liabilities (2)			(23)				(34)
Regulatory assets (1)			25				36
Regulatory liabilities (2)			(46)				(25)
Net asset		$	2			$	1
HFT Derivatives:
Derivative instrument assets (1)		$	185			$	158
Derivative instrument liabilities (2)			(594)				(614)
Net liability		$	(409)			$	(456)
Other Derivatives:
Derivative instrument assets (1)		$	25			$	16
Derivative instrument liabilities (2)			(4)				(1)
Net asset		$	21			$	15

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

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

 

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Realized and Unrealized Gains (Losses) Recognized in Net Income

 

For the		Three months ended March 31
millions of dollars		2026				2025
Regulatory Deferral:
Regulated fuel for generation and purchased power (1)		$	(1)			$	(1)
HFT Derivatives:
Non-regulated operating revenues		$	341			$	466
Other Derivatives:
OM&G		$	22			$	20
Other income, net			(7)				(4)
Net gains		$	15			$	16
Total net gains		$	355			$	481

(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 recorded in inventory will be recognized in “Regulated fuel for generation and purchased power” when the hedged item is consumed.

As of March 31, 2026, the unrealized gain in Accumulated Other Comprehensive Income was $10 million, after-tax (December 31, 2025 – $10 million, after-tax).

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 March 31, 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. This transition to business continuity processes resulted in a material change in the Company’s ICFR at Canadian affiliates during the quarter ended June 30, 2025. Since that time, the Company has restored certain financial systems and transitioned back from corresponding business continuity processes, which resulted in a material change in the Company’s ICFR at its Canadian affiliates during the period ended March 31, 2026. For more information on the Cybersecurity Incident, refer to the “Other Developments” section.

There were no other changes in the Company’s ICFR during the quarter ended March 31, 2026, that have materially affected, or are reasonably likely to materially affect, the Company’s ICFR.

 

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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 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.

 

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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		Q1				Q4				Q3				Q2				Q1				Q4				Q3				Q2
(except per share amounts)		2026				2025				2025				2025				2025				2024				2024				2024
Operating revenues		$	2,813			$	2,006			$	2,106			$	1,988			$	2,676			$	1,763			$	1,802			$	1,617
Net income attributable to common shareholders		$	562			$	68			$	228			$	135			$	583			$	154			$	4			$	129
EPS – basic		$	1.85			$	0.23			$	0.76			$	0.45			$	1.96			$	0.52			$	0.01			$	0.45
EPS – diluted		$	1.85			$	0.25			$	0.76			$	0.45			$	1.96			$	0.52			$	0.01			$	0.45

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.

Q1 2026 compared to Q1 2025

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

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.

 

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Q2 2025 compared to Q2 2024

Q2 2025 net income attributable to common shareholders increased by $6 million primarily due to decreased MTM losses; increased earnings at TEC, EES, and NMGC; higher Corporate income tax recovery; and decreased Corporate OM&G. These were partially offset by the gain on sale of LIL recognized in Q2 2024; charges related to the pending sale of NMGC recognized in Q2 2025; lower earnings at NSPI; decreased equity earnings from LIL; and increased Corporate interest expense. Q2 2025 EPS – basic and diluted were consistent with Q2 2024.

 

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