Emera Inc 6-K, filed May 8, 2026
Emera Inc (EMA)
About this 6-K
Emera Inc filed this 6-K on May 8, 2026.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 6-K
REPORT OF FOREIGN PRIVATE ISSUER
PURSUANT TO RULE 13a-16 OR 15d-16
UNDER THE SECURITIES EXCHANGE ACT OF 1934
For the month of May, 2026
Commission File Number: 001-42631
Emera Incorporated
(Exact name of registrant as specified in its charter)
5151 Terminal Road
Halifax NS B3J 1A1
Canada
(Address of principal executive offices)
Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.
Form 20-F ☐ Form 40-F ☒
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ☐
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ☐
Exhibits 99.1 and 99.2 of this Form 6-K are incorporated by reference into the registration statements on Form F-10 (File Nos. 333-291985 and 333-294020), on Form F-3 (File Nos. 333-294017, 333-294017-01 and 333-294017-02) and on Form S-8 (File No. 333-287613).
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| EMERA INCORPORATED | ||||||
| Date: May 8, 2026 | By: | /s/ Brian Curry | ||||
| Name: Brian Curry Title: Corporate Secretary | ||||||
EXHIBIT INDEX
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 |
2 | |||
| Introduction and Strategic Overview |
3 | |||
| Non-GAAP Financial Measures and Ratios |
4 | |||
| Consolidated Financial Review |
5 | |||
| Significant Items Affecting Earnings |
5 | |||
| Consolidated Financial Highlights |
6 | |||
| Consolidated Income Statement Highlights |
7 | |||
| Business Overview and Outlook |
9 | |||
| Florida Electric Utility |
9 | |||
| Canadian Electric Utilities |
9 | |||
| Gas Utilities and Infrastructure |
10 | |||
| Other Electric Utilities |
10 | |||
| Other |
10 | |||
| Consolidated Balance Sheet Highlights |
11 | |||
| Other Developments |
12 | |||
| Financial Highlights |
13 | |||
| Florida Electric Utility |
13 |
| Canadian Electric Utilities |
13 | |||
| Gas Utilities and Infrastructure |
14 | |||
| Other Electric Utilities |
15 | |||
| Other |
16 | |||
| Liquidity and Capital Resources |
17 | |||
| Consolidated Cash Flow Highlights |
18 | |||
| Contractual Obligations |
19 | |||
| Debt Management |
20 | |||
| Guarantees and Letters of Credit |
22 | |||
| Outstanding Stock Data |
22 | |||
| Transactions with Related Parties |
23 | |||
| Risk Management and Financial Instruments |
23 | |||
| Disclosure and Internal Controls |
24 | |||
| Critical Accounting Estimates |
25 | |||
| Changes in Accounting Policies and Practices |
25 | |||
| Future Accounting Pronouncements |
25 | |||
| Summary of Quarterly Results |
26 |
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.
2
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.
4
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.
7
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).
10
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.
11
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.
21
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.
22
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. |
| • | 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.
23
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.
24
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.
25
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.
26
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.
27
Exhibit 99.2
EMERA INCORPORATED
Unaudited Condensed Consolidated
Interim Financial Statements
March 31, 2026 and 2025
1
Emera Incorporated
Condensed Consolidated Statements of Income (Unaudited)
| For the |
Three months ended March 31 | |||||||
| millions of dollars (except per share amounts) |
2026 | 2025 | ||||||
| Operating revenues |
||||||||
| Regulated electric |
$ | 1,836 | $ | 1,660 | ||||
| Regulated gas |
568 | 605 | ||||||
| Non-regulated |
409 | 411 | ||||||
| Total operating revenues (note 5) |
2,813 | 2,676 | ||||||
| Operating expenses |
||||||||
| Regulated fuel for generation and purchased power |
642 | 575 | ||||||
| Regulated cost of natural gas |
155 | 220 | ||||||
| Operating, maintenance and general expenses (“OM&G”) |
604 | 518 | ||||||
| Provincial, state and municipal taxes |
130 | 119 | ||||||
| Depreciation and amortization |
339 | 319 | ||||||
| Total operating expenses |
1,870 | 1,751 | ||||||
| Income from operations |
943 | 925 | ||||||
| Income from equity investments (note 7) |
21 | 19 | ||||||
| Other income, net |
18 | 31 | ||||||
| Interest expense, net |
271 | 255 | ||||||
| Income before provision for income taxes |
711 | 720 | ||||||
| Income tax expense (note 8) |
129 | 119 | ||||||
| Net income |
582 | 601 | ||||||
| Preferred stock dividends |
20 | 18 | ||||||
| Net income attributable to common shareholders |
$ | 562 | $ | 583 | ||||
| Weighted average shares of common stock outstanding (in millions) (note 10) |
||||||||
| Basic |
303.3 | 297.0 | ||||||
| Diluted |
304.2 | 297.3 | ||||||
| Earnings per common share (note 10) |
||||||||
| Basic |
$ | 1.85 | $ | 1.96 | ||||
| Diluted |
$ | 1.85 | $ | 1.96 | ||||
| Dividends per common share declared |
$ | 0.7325 | $ | 0.7250 | ||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
2
Emera Incorporated
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
| For the |
Three months ended March 31 | |||||||
| millions of dollars |
2026 | 2025 | ||||||
| Net income |
$ | 582 | $ | 601 | ||||
| Other comprehensive income (loss) (“OCI”), net of tax |
||||||||
| Foreign currency translation adjustment |
230 | (12) | ||||||
| Unrealized (losses) gains on net investment hedges (1) |
(28) | 2 | ||||||
| Unrealized loss on available-for-sale investment |
(1) | - | ||||||
| Net change in unrecognized pension and post-retirement benefit obligation |
(5) | (4) | ||||||
| OCI |
$ | 196 | $ | (14) | ||||
| Comprehensive Income of Emera Incorporated |
$ | 778 | $ | 587 | ||||
1) The Company has designated $1.2 billion US dollar (“USD”) denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in USD denominated operations.
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
3
Emera Incorporated
Condensed Consolidated Balance Sheets (Unaudited)
| As at |
March 31 | December 31 | ||||||
| millions of dollars |
2026 | 2025 | ||||||
| Assets |
||||||||
| Current assets |
||||||||
| Cash and cash equivalents |
$ | 2,457 | $ | 349 | ||||
| Restricted cash |
13 | 16 | ||||||
| Inventory |
806 | 821 | ||||||
| Derivative instruments (notes 12 and 13) |
215 | 156 | ||||||
| Regulatory assets (note 6) |
351 | 409 | ||||||
| Receivables and other current assets (note 15) |
2,581 | 2,439 | ||||||
| Assets held for sale (note 3) |
163 | 199 | ||||||
| 6,586 | 4,389 | |||||||
| Property, plant and equipment (“PP&E”), net of accumulated depreciation and amortization of $11,177 and $10,845, respectively | 28,270 | 27,408 | ||||||
| Other assets |
||||||||
| Deferred income taxes (note 8) |
333 | 421 | ||||||
| Derivative instruments (notes 12 and 13) |
41 | 42 | ||||||
| Regulatory assets (note 6) |
2,894 | 2,789 | ||||||
| Net investment in direct finance and sales type leases |
568 | 572 | ||||||
| Investments subject to significant influence (note 7) |
638 | 634 | ||||||
| Goodwill |
5,675 | 5,580 | ||||||
| Other long-term assets (note 22) |
919 | 894 | ||||||
| Assets held for sale (note 3) |
2,138 | 2,088 | ||||||
| 13,206 | 13,020 | |||||||
| Total assets |
$ | 48,062 | $ | 44,817 |
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
4
Emera Incorporated
Condensed Consolidated Balance Sheets (Unaudited) – Continued
| As at |
March 31 | December 31 | ||||||
| millions of dollars |
2026 | 2025 | ||||||
| Liabilities and Equity |
||||||||
| Current liabilities |
||||||||
| Short-term debt (note 17) |
$ | 1,497 | $ | 1,807 | ||||
| Current portion of long-term debt (note 18) |
1,254 | 1,201 | ||||||
| Accounts payable |
1,674 | 1,948 | ||||||
| Derivative instruments (notes 12 and 13) |
526 | 534 | ||||||
| Regulatory liabilities (note 6) |
198 | 211 | ||||||
| Other current liabilities |
712 | 535 | ||||||
| Liabilities associated with assets held for sale (note 3) |
315 | 391 | ||||||
| 6,176 | 6,627 | |||||||
| Long-term liabilities |
||||||||
| Long-term debt (note 18) |
21,206 | 18,453 | ||||||
| Deferred income taxes (note 8) |
2,624 | 2,516 | ||||||
| Derivative instruments (notes 12 and 13) |
95 | 115 | ||||||
| Regulatory liabilities (note 6) |
1,489 | 1,458 | ||||||
| Pension and post-retirement liabilities |
270 | 268 | ||||||
| Other long-term liabilities |
950 | 960 | ||||||
| Liabilities associated with assets held for sale (note 3) |
1,048 | 1,024 | ||||||
| 27,682 | 24,794 | |||||||
| Equity |
||||||||
| Common stock (note 9) |
9,658 | 9,387 | ||||||
| Cumulative preferred stock (note 20) |
1,422 | 1,422 | ||||||
| Contributed surplus |
87 | 86 | ||||||
| Accumulated other comprehensive income (“AOCI”) (note 11) |
1,069 | 873 | ||||||
| Retained earnings |
1,954 | 1,614 | ||||||
| Total Emera Incorporated equity |
14,190 | 13,382 | ||||||
| Non-controlling interest in subsidiaries (“NCI”) |
14 | 14 | ||||||
| Total equity |
14,204 | 13,396 | ||||||
| Total liabilities and equity |
$ | 48,062 | $ | 44,817 | ||||
| Commitments and contingencies (note 19) |
||||||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
| Approved on behalf of the Board of Directors | ||
| “Karen Sheriff” | “Scott Balfour” | |
| Chair of the Board | President and Chief Executive Officer | |
5
Emera Incorporated
Condensed Consolidated Statements of Cash Flows (Unaudited)
| For the | Three months ended March 31 | |||||||
| millions of dollars | 2026 | 2025 | ||||||
| Operating activities | ||||||||
| Net income | $ | 582 | $ | 601 | ||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
| Depreciation and amortization |
337 | 321 | ||||||
| Income from equity investments, net of dividends |
(5) | 3 | ||||||
| Allowance for funds used during construction (“AFUDC”) – equity |
(12) | (18) | ||||||
| Deferred income taxes, net |
118 | 137 | ||||||
| Net change in pension and post-retirement liabilities |
(10) | (9) | ||||||
| Nova Scotia Power Inc. (“NSPI”) fuel adjustment mechanism (“FAM”) |
(22) | (78) | ||||||
| Net change in fair value (“FV”) of derivative instruments |
(63) | (254) | ||||||
| Net change in regulatory assets and liabilities |
12 | 38 | ||||||
| Net change in capitalized transportation capacity |
(168) | (41) | ||||||
| Other operating activities, net |
6 | 33 | ||||||
| Changes in non-cash working capital (note 21) |
(40) | (34) | ||||||
| Net cash provided by operating activities |
735 | 699 | ||||||
| Investing activities |
||||||||
| Additions to PP&E |
(879) | (724) | ||||||
| Proceeds on disposal of assets |
9 | 16 | ||||||
| Other investing activities |
(2) | - | ||||||
| Net cash used in investing activities |
(872) | (708) | ||||||
| Financing activities |
||||||||
| Change in short-term debt, net |
162 | (711) | ||||||
| Proceeds from long-term debt, net of issuance costs |
2,049 | 905 | ||||||
| Retirement of long-term debt |
(5) | (7) | ||||||
| Net (repayments) proceeds under committed credit facilities |
(25) | 73 | ||||||
| Issuance of common stock, net of issuance costs |
198 | 20 | ||||||
| Dividends on common stock |
(150) | (139) | ||||||
| Dividends on preferred stock |
(20) | (18) | ||||||
| Other financing activities |
(1) | - | ||||||
| Net cash provided by financing activities |
2,208 | 123 | ||||||
| Effect of exchange rate changes on cash, cash equivalents, restricted cash and cash associated with assets held for sale | 37 | - | ||||||
| Net increase in cash, cash equivalents, restricted cash, and cash associated with assets held for sale | 2,108 | 114 | ||||||
| Cash, cash equivalents, restricted cash and cash associated with assets held for sale, beginning of period | 371 | 221 | ||||||
| Cash, cash equivalents, restricted cash and cash associated with assets held for sale, end of period |
$ | 2,479 | $ | 335 | ||||
| Cash, cash equivalents, restricted cash and cash associated with assets held for sale consists of: | ||||||||
| Cash |
$ | 2,452 | $ | 303 | ||||
| Short-term investments |
5 | 5 | ||||||
| Restricted cash |
13 | 18 | ||||||
| Cash associated with assets held for sale |
9 | 9 | ||||||
| Total |
$ | 2,479 | $ | 335 | ||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
6
Emera Incorporated
Condensed Consolidated Statements of Changes in Equity (Unaudited)
| Common | Preferred | Contributed | Retained | Total | ||||||||||||||||||||||||
| millions of dollars |
Stock | Stock | Surplus | AOCI | Earnings | NCI | Equity | |||||||||||||||||||||
| For the three months ended March 31, 2026 |
| |||||||||||||||||||||||||||
| Balance, December 31, 2025 |
$ | 9,387 | $ | 1,422 | $ | 86 | $ | 873 | $ | 1,614 | $ | 14 | $ | 13,396 | ||||||||||||||
| Net income of Emera Incorporated |
- | - | - | - | 582 | - | 582 | |||||||||||||||||||||
| OCI, net of tax expense of nil |
- | - | - | 196 | - | - | 196 | |||||||||||||||||||||
| Dividends declared on preferred stock (1) |
- | - | - | - | (20) | - | (20) | |||||||||||||||||||||
| Dividends declared on common stock ($0.7325/share) | - | - | - | - | (222) | - | (222) | |||||||||||||||||||||
| Issuance of common stock under the at-the-market (“ATM”) program, net of after-tax issuance costs | 184 | - | - | - | - | - | 184 | |||||||||||||||||||||
| Issued under the Dividend Reinvestment Program (“DRIP”), net of discounts | 71 | - | - | - | - | - | 71 | |||||||||||||||||||||
| Senior management stock options exercised and Employee Common Share Purchase Plan (“ECSPP”) | 16 | - | 1 | - | - | - | 17 | |||||||||||||||||||||
| Balance, March 31, 2026 |
$ | 9,658 | $ | 1,422 | $ | 87 | $ | 1,069 | $ | 1,954 | $ | 14 | $ | 14,204 | ||||||||||||||
| For the three months ended March 31, 2025 |
| |||||||||||||||||||||||||||
| Balance, December 31, 2024 |
$ | 9,042 | $ | 1,422 | $ | 84 | $ | 1,261 | $ | 1,468 | $ | 14 | $ | 13,291 | ||||||||||||||
| Net income of Emera Incorporated | - | - | - | - | 601 | - | 601 | |||||||||||||||||||||
| OCI, net of tax expense of nil | - | - | - | (14) | - | - | (14) | |||||||||||||||||||||
| Dividends declared on preferred stock (2) | - | - | - | - | (18) | - | (18) | |||||||||||||||||||||
| Dividends declared on common stock ($0.7250/share) | - | - | - | - | (215) | - | (215) | |||||||||||||||||||||
| Issued under the DRIP, net of discount | 76 | - | - | - | - | - | 76 | |||||||||||||||||||||
| Issuance under ATM program, net of after-tax issuance costs | 10 | - | - | - | - | - | 10 | |||||||||||||||||||||
| Senior management stock options exercised and ECSPP | 12 | - | - | - | - | - | 12 | |||||||||||||||||||||
| Balance, March 31, 2025 |
$ | 9,140 | $ | 1,422 | $ | 84 | $ | 1,247 | $ | 1,836 | $ | 14 | $ | 13,743 | ||||||||||||||
(1) Series A; $0.3094/share, Series C; $0.4021/share, Series E; $0.2813/share, Series F; $0.3593/share; Series H; $0.3953/share; Series J; $0.2656/share and Series L; $0.2875/share
(2) Series A; $0.1364/share, Series B; $0.3630/share, Series C; $0.4021/share, Series E; $0.2813/share, Series F; $0.2626/share; Series H; $0.3953/share; Series J; $0.2656/share and Series L; $0.2875/share
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
7
Emera Incorporated
Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)
As at March 31, 2026 and 2025
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
Emera Incorporated (“Emera” or the “Company”) is an energy and services company that invests in electricity generation, transmission and distribution, and gas transmission and distribution. At March 31, 2026, Emera’s reportable segments include the following:
| ● | Florida Electric Utility, which consists of Tampa Electric (“TEC”), a vertically integrated regulated electric utility in West Central Florida. |
| ● | Canadian Electric Utilities, which includes: |
| ● | NSPI, a vertically integrated regulated electric utility and the primary electricity supplier in Nova Scotia; |
| ● | a 100 per cent equity interest in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link Project, a $1.8 billion, including AFUDC, transmission project between the island of Newfoundland and Nova Scotia; and |
| ● | a 50 per cent indirect voting equity interest in Wasoqonatl Transmission Incorporated (“WTI”), a transmission line project to create a reliability intertie between Nova Scotia and New Brunswick. |
| ● | Gas Utilities and Infrastructure, which includes: |
| ● | Peoples Gas System, Inc. (“PGS”), a regulated gas distribution utility operating across Florida; |
| ● | New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility serving customers in New Mexico. On August 5, 2024, Emera announced an agreement to sell NMGC. The transaction is now expected to close mid-2026, subject to certain approvals, including approval by the New Mexico Public Regulation Commission (“NMPRC”). For more information on the pending transaction, refer to note 3; |
| ● | Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick to the United States (“US”) border under a 25-year firm service agreement with Repsol Energy North America Canada Partnership (“Repsol Energy”), which expires in 2034; |
| ● | SeaCoast Gas Transmission, LLC (“SeaCoast”), a regulated intrastate natural gas transmission company offering services in Florida; and |
| ● | a 12.9 per cent equity interest in Maritimes & Northeast Pipeline (“M&NP”), a 1,400-kilometre pipeline that transports natural gas throughout markets in Atlantic Canada and the northeastern US. |
| ● | Other Electric Utilities, which includes Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities that include: |
| ● | The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated regulated electric utility on the island of Barbados; |
| ● | Grand Bahama Power Company Limited (“GBPC”), a vertically integrated regulated electric utility on Grand Bahama Island. On May 5, 2026, Emera entered into an agreement to sell GBPC. For more information on the pending sale, refer to note 3; and |
| ● | a 19.5 per cent equity interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility on the island of St. Lucia. |
8
| ● | Emera’s other segment includes investments in energy-related non-regulated companies that are below the required threshold for reporting as separate segments and corporate expense and revenue items that are not directly allocated to the operations of Emera’s subsidiaries and investments. This includes: |
| ● | Emera Energy, which consists of: |
| ● | Emera Energy Services (“EES”), a physical energy business that purchases and sells natural gas and electricity and provides related energy asset management services; |
| ● | Brooklyn Power Corporation (“Brooklyn Energy”), a 30 MW biomass co-generation electricity facility in Brooklyn, Nova Scotia; and |
| ● | a 50 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a 660 MW pumped storage hydroelectric facility in northwestern Massachusetts. |
| ● | Emera US Finance LP, Emera US Finance, LLC (“Emera Finance”), EUSHI Finance, Inc. (“EUSHI Finance”) and TECO Finance, Inc., financing subsidiaries of Emera; |
| ● | Emera US Holdings Inc. (“EUSHI”), a wholly owned holding company for certain of Emera’s assets located in the US; and |
| ● | Other investments. |
Basis of Presentation
These unaudited condensed consolidated interim financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”). The significant accounting policies applied to these unaudited condensed consolidated interim financial statements are consistent with those disclosed in the audited consolidated financial statements as at and for the year ended December 31, 2025.
In the opinion of management, these unaudited condensed consolidated interim financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 2026.
All dollar amounts are presented in Canadian dollars, unless otherwise indicated.
Use of Management Estimates
The preparation of unaudited condensed consolidated interim financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during 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 audited consolidated financial statements.
9
Seasonal Nature of Operations
Interim results are not necessarily indicative of results for the full year, primarily due to seasonal factors. Electricity and gas sales, and related transmission and distribution, vary during the year. The first quarter provides strong earnings contributions from the Canadian Electric Utilities and Gas Utilities and Infrastructure segments, where winter is the peak electricity and gas usage season. The third quarter provides strong earnings contributions from the Florida Electric Utility segment due to summer being the heaviest electric consumption season. Certain quarters may also be impacted by weather and the number and severity of storms.
Cybersecurity Incident
On April 25, 2025, Emera and NSPI discovered a cybersecurity incident (the “Cybersecurity Incident”) involving unauthorized access into certain parts of its Canadian information technology (“IT”) network and servers supporting portions of its business applications. There was no disruption to the Canadian physical operations or to 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. The Company maintains cyber insurance coverage and is working with its insurer on the claims process.
2. FUTURE ACCOUNTING PRONOUNCEMENTS
The Company considers the applicability and impact of all Accounting Standard Updates (“ASU”) issued by the Financial Accounting Standards Board (“FASB”). The following updates have been issued by the FASB but, as allowed, have not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be either not applicable to the Company or to have an insignificant impact on the consolidated financial statements.
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.
10
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.
3. DISPOSITIONS
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.
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.
11
Details of the assets and liabilities classified as held for sale are as follows:
| As at millions of dollars |
March 31 2026 |
December 31 2025 |
||||||
| Cash and cash equivalents |
$ | 9 | $ | 6 | ||||
| Inventory |
7 | 10 | ||||||
| Regulatory assets |
44 | 41 | ||||||
| Receivables and other current assets |
103 | 142 | ||||||
| Current assets held for sale |
$ | 163 | $ | 199 | ||||
| PP&E |
1,904 | 1,856 | ||||||
| Regulatory assets |
4 | 4 | ||||||
| Goodwill |
294 | 289 | ||||||
| Other long-term assets |
26 | 28 | ||||||
| Less: Adjustment to FV less costs to sell |
(90) | (89) | ||||||
| Long-term assets held for sale |
$ | 2,138 | $ | 2,088 | ||||
| Total assets held for sale |
$ | 2,301 | $ | 2,287 | ||||
| Short-term debt |
$ | 104 | $ | 116 | ||||
| Current portion of long-term debt |
98 | 96 | ||||||
| Regulatory liabilities |
12 | 25 | ||||||
| Accounts payable and other current liabilities |
101 | 154 | ||||||
| Current liabilities associated with assets held for sale |
315 | 391 | ||||||
| Long-term debt |
577 | 567 | ||||||
| Deferred income taxes |
196 | 185 | ||||||
| Regulatory liabilities |
264 | 261 | ||||||
| Other long-term liabilities |
11 | 11 | ||||||
| Long-term liabilities associated with assets held for sale |
$ | 1,048 | $ | 1,024 | ||||
| Total liabilities associated with assets held for sale |
$ | 1,363 | $ | 1,415 | ||||
4. SEGMENT INFORMATION
Emera manages its reportable segments separately due in part to their different operating, regulatory and geographical environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets, as reported to the Company’s chief operating decision maker (“CODM”). Emera’s CODM is the Chief Executive Officer.
12
| millions of dollars | Florida Electric Utility |
Canadian Electric Utilities |
Gas Utilities and Infrastructure |
Other Electric Utilities |
Other | Inter- Segment Eliminations |
Total | |||||||||||||||||||||
| For the three months ended March 31, 2026 |
| |||||||||||||||||||||||||||
| Operating revenues from external customers (1) |
$ | 1,098 | $ | 612 | $ | 573 | $ | 127 | $ | 403 | $ | - | $ | 2,813 | ||||||||||||||
| Inter-segment revenues (1) |
2 | - | 5 | - | 5 | (12) | - | |||||||||||||||||||||
| Total operating revenues |
1,100 | 612 | 578 | 127 | 408 | (12) | 2,813 | |||||||||||||||||||||
| Regulated fuel for generation and purchased power |
293 | 293 | - | 61 | - | (5) | 642 | |||||||||||||||||||||
| Regulated cost of natural gas |
- | - | 155 | - | - | - | 155 | |||||||||||||||||||||
| OM&G |
271 | 129 | 120 | 34 | 60 | (10) | 604 | |||||||||||||||||||||
| Provincial, state and municipal taxes |
81 | 12 | 36 | 1 | - | - | 130 | |||||||||||||||||||||
| Depreciation and amortization |
184 | 79 | 53 | 21 | 2 | - | 339 | |||||||||||||||||||||
| Income from equity investments |
- | 12 | 5 | 1 | 3 | - | 21 | |||||||||||||||||||||
| Other income (expense), net |
17 | 6 | 3 | 1 | (6) | (3) | 18 | |||||||||||||||||||||
| Interest expense, net (2) |
81 | 44 | 37 | 5 | 104 | - | 271 | |||||||||||||||||||||
| Income tax expense (recovery) |
27 | (13) | 49 | - | 66 | - | 129 | |||||||||||||||||||||
| Preferred stock dividends |
- | - | - | - | 20 | - | 20 | |||||||||||||||||||||
| Net income attributable to common shareholders |
$ | 180 | $ | 86 | $ | 136 | $ | 7 | $ | 153 | $ | - | $ | 562 | ||||||||||||||
| As at March 31, 2026 |
||||||||||||||||||||||||||||
| Total assets |
$ | 25,718 | $ | 8,806 | $ | 8,766 | $ | 1,464 | $ | 4,483 | $ | (1,175) | $ | 48,062 | ||||||||||||||
| Investments subject to significant influence |
$ | - | $ | 473 | $ | 109 | $ | 56 | $ | - | $ | - | $ | 638 | ||||||||||||||
| Goodwill |
$ | 4,877 | $ | - | $ | 798 | $ | - | $ | - | $ | - | $ | 5,675 | ||||||||||||||
| For the three months ended March 31, 2025 |
| |||||||||||||||||||||||||||
| Operating revenues from external customers (1) |
$ | 930 | $ | 599 | $ | 611 | $ | 131 | $ | 405 | $ | - | $ | 2,676 | ||||||||||||||
| Inter-segment revenues (1) |
2 | - | 4 | - | 12 | (18) | - | |||||||||||||||||||||
| Total operating revenues |
932 | 599 | 615 | 131 | 417 | (18) | 2,676 | |||||||||||||||||||||
| Regulated fuel for generation and purchased power |
232 | 280 | - | 68 | - | (5) | 575 | |||||||||||||||||||||
| Regulated cost of natural gas |
- | - | 220 | - | - | - | 220 | |||||||||||||||||||||
| OM&G |
212 | 120 | 123 | 36 | 35 | (8) | 518 | |||||||||||||||||||||
| Provincial, state and municipal taxes |
72 | 12 | 34 | 1 | - | - | 119 | |||||||||||||||||||||
| Depreciation and amortization |
175 | 73 | 51 | 18 | 2 | - | 319 | |||||||||||||||||||||
| Income from equity investments |
- | 11 | 6 | 1 | 1 | - | 19 | |||||||||||||||||||||
| Other income (expenses), net |
23 | 7 | 5 | (1) | (8) | 5 | 31 | |||||||||||||||||||||
| Interest expense, net (2) |
74 | 41 | 37 | 5 | 98 | - | 255 | |||||||||||||||||||||
| Income tax expense (recovery) |
26 | (30) | 41 | 3 | 79 | - | 119 | |||||||||||||||||||||
| Preferred stock dividends |
- | - | - | - | 18 | - | 18 | |||||||||||||||||||||
| Net income attributable to common shareholders |
$ | 164 | $ | 121 | $ | 120 | $ | - | $ | 178 | $ | - | $ | 583 | ||||||||||||||
| As at December 31, 2025 |
||||||||||||||||||||||||||||
| Total assets |
$ | 24,636 | $ | 8,546 | $ | 8,476 | $ | 1,439 | $ | 2,469 | $ | (749) | $ | 44,817 | ||||||||||||||
| Investments subject to significant influence |
$ | - | $ | 471 | $ | 108 | $ | 55 | $ | - | $ | - | $ | 634 | ||||||||||||||
| Goodwill |
$ | 4,796 | $ | - | $ | 784 | $ | - | $ | - | $ | - | $ | 5,580 | ||||||||||||||
(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E, OM&G, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments.
(2) Segment net income is reported on a basis that includes internally allocated financing costs of $6 million for the three months ended March 31, 2026, between the Gas Utilities and Infrastructure and Other segments (2025 – $6 million).
13
5. REVENUE
The following disaggregates the Company’s revenue by major source:
| Electric | Gas | Other | ||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||||||||||||||
| millions of dollars | Florida Electric Utility |
Canadian Electric Utilities |
Other Electric Utilities |
Gas Utilities and Infrastructure |
Other | Inter- Segment Eliminations |
Total | |||||||||||||||||||||||||
| For the three months ended March 31, 2026 |
| |||||||||||||||||||||||||||||||
| Regulated Revenue: |
||||||||||||||||||||||||||||||||
| Residential |
$ | 554 | $ | 370 | $ | 43 | $ | 273 | $ | - | $ | - | $ | 1,240 | ||||||||||||||||||
| Commercial |
272 | 154 | 66 | 164 | - | - | 656 | |||||||||||||||||||||||||
| Industrial |
65 | 65 | 6 | 27 | - | (6) | 157 | |||||||||||||||||||||||||
| Other electric |
206 | 15 | 2 | - | - | - | 223 | |||||||||||||||||||||||||
| Regulatory deferrals |
(2) | - | 7 | - | - | - | 5 | |||||||||||||||||||||||||
| Other (1) |
5 | 8 | 3 | 94 | - | (2) | 108 | |||||||||||||||||||||||||
| Finance income (2)(3) |
- | - | - | 15 | - | - | 15 | |||||||||||||||||||||||||
| Regulated revenue |
1,100 | 612 | 127 | 573 | - | (8) | 2,404 | |||||||||||||||||||||||||
| Non-Regulated Revenue: |
||||||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
- | - | - | - | 183 | - | 183 | |||||||||||||||||||||||||
| Other non-regulated operating revenues |
- | - | - | 5 | 14 | (9) | 10 | |||||||||||||||||||||||||
|
Mark-to-market (3) |
- | - | - | - | 211 | 5 | 216 | |||||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 5 | 408 | (4) | 409 | |||||||||||||||||||||||||
| Total operating revenues |
$ | 1,100 | $ | 612 | $ | 127 | $ | 578 | $ | 408 | $ | (12) | $ | 2,813 | ||||||||||||||||||
| For the three months ended March 31, 2025 |
| |||||||||||||||||||||||||||||||
| Regulated Revenue: |
||||||||||||||||||||||||||||||||
| Residential |
$ | 483 | $ | 361 | $ | 42 | $ | 314 | $ | - | $ | - | $ | 1,200 | ||||||||||||||||||
| Commercial |
247 | 148 | 75 | 178 | - | - | 648 | |||||||||||||||||||||||||
| Industrial |
66 | 68 | 6 | 26 | - | (4) | 162 | |||||||||||||||||||||||||
| Other electric |
116 | 12 | 2 | - | - | - | 130 | |||||||||||||||||||||||||
| Regulatory deferrals |
14 | - | 3 | - | - | - | 17 | |||||||||||||||||||||||||
| Other (1) |
6 | 10 | 3 | 74 | - | (2) | 91 | |||||||||||||||||||||||||
| Finance income (2)(3) |
- | - | - | 17 | - | - | 17 | |||||||||||||||||||||||||
| Regulated revenue |
932 | 599 | 131 | 609 | - | (6) | 2,265 | |||||||||||||||||||||||||
| Non-Regulated: |
||||||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
- | - | - | - | 120 | - | 120 | |||||||||||||||||||||||||
| Other non-regulated operating revenues |
- | - | - | 6 | 9 | (6) | 9 | |||||||||||||||||||||||||
|
Mark-to-market (3) |
- | - | - | - | 288 | (6) | 282 | |||||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 6 | 417 | (12) | 411 | |||||||||||||||||||||||||
| Total operating revenues |
$ | 932 | $ | 599 | $ | 131 | $ | 615 | $ | 417 | $ | (18) | $ | 2,676 | ||||||||||||||||||
(1) Other includes rental revenues, which do not represent revenue from contracts with customers.
(2) Revenue related to Brunswick Pipeline’s service agreement with Repsol Energy.
(3) Revenue which does not represent revenues from contracts with customers.
(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with customers.
Remaining Performance Obligations:
Remaining performance obligations primarily represent gas transportation contracts, and long-term steam supply arrangements with fixed contract terms. As of March 31, 2026, the aggregate amount of the transaction price allocated to remaining performance obligations was $338 million (2025 – $480 million), including $10 million related to NMGC. This amount includes $120 million of future performance obligations related to a gas transportation contract between SeaCoast and PGS through 2040, and $21 million of future performance obligations related to asset management agreements between PGS and EES through 2030. This amount excludes contracts with an original expected length of one year or less and variable amounts for which Emera recognizes revenue at the amount to which it has the right to invoice for services performed. Emera expects to recognize revenue for the remaining performance obligations through 2040.
14
6. REGULATORY ASSETS AND LIABILITIES
A summary of regulatory assets and liabilities is provided below. For a detailed description regarding the nature of the Company’s regulatory assets and liabilities, refer to note 7 in Emera’s 2025 annual audited consolidated financial statements. Updates to regulatory environments are included below.
| As at millions of dollars |
March 31 2026 |
December 31 2025 |
||||||
| Regulatory assets (1) |
||||||||
| Deferred income tax regulatory assets |
$ | 1,431 | $ | 1,385 | ||||
| TEC capital cost recovery for early retired assets |
741 | 727 | ||||||
| Pension and post-retirement medical plan |
318 | 316 | ||||||
| TEC capital cost recovery for retired Polk Unit 1 components |
176 | 178 | ||||||
| NSPI FAM |
128 | 102 | ||||||
| Storm cost recovery clauses |
122 | 206 | ||||||
| Cost recovery clauses |
79 | 55 | ||||||
| Environmental remediations |
27 | 26 | ||||||
| Deferrals related to derivative instruments |
25 | 36 | ||||||
| Stranded cost recovery |
25 | 25 | ||||||
| Other (2) |
173 | 142 | ||||||
| $ | 3,245 | $ | 3,198 | |||||
| Current |
$ | 351 | $ | 409 | ||||
| Long-term |
2,894 | 2,789 | ||||||
| Total regulatory assets |
$ | 3,245 | $ | 3,198 | ||||
| Regulatory liabilities (1) |
||||||||
| Accumulated reserve – cost of removal |
$ | 757 | $ | 729 | ||||
| Deferred income tax regulatory liabilities |
752 | 751 | ||||||
| Deferrals related to derivative instruments |
46 | 25 | ||||||
| Cost recovery clauses |
43 | 75 | ||||||
| BLPC Self-insurance fund (“SIF”) (note 22) |
31 | 30 | ||||||
| Other (2) |
58 | 59 | ||||||
| $ | 1,687 | $ | 1,669 | |||||
| Current |
$ | 198 | $ | 211 | ||||
| Long-term |
1,489 | 1,458 | ||||||
| Total regulatory liabilities |
$ | 1,687 | $ | 1,669 | ||||
(1) On August 5, 2024, Emera announced an agreement to sell NMGC. As a result, NMGC’s assets and liabilities were classified as held for sale beginning in Q3 2024 and excluded from the table above. For further details on the pending transaction, refer to note 3.
(2) Comprised of regulatory assets and liabilities that are not individually significant.
Florida Electric Utility
On February 3, 2025, the Floria Public Service Commission (“FPSC”) issued the final order approving the 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. To date, the intervening parties have not filed their briefs related to the appeal. 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.
15
Canadian Electric Utilities
NSPI
On April 30, 2026, the Nova Scotia Energy Board (“NSEB”) approved the General Rate Application (“GRA”) with changes effective May 1, 2026. This results in an average annual customer rate increase of 1.2 per cent, and a further average increase of 2.5 per cent on January 1, 2027. Any under or over-recovery of fuel costs is addressed through the NSEB’s established FAM process. NSPI’s return on equity 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.
7. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME
| Carrying Value as at |
Equity Income for the three months ended |
Percentage of |
||||||||||||||||||
| millions of dollars | March 31 2026 |
December 31 2025 |
2026 | March 31 2025 |
Ownership 2026 |
|||||||||||||||
| NSPML |
464 | 462 | 12 | 11 | 100.0 | |||||||||||||||
| M&NP (1) |
109 | 108 | 5 | 6 | 12.9 | |||||||||||||||
| Lucelec (1) |
56 | 55 | 1 | 1 | 19.5 | |||||||||||||||
| WTI (2) |
9 | 9 | - | - | 50.0 | |||||||||||||||
| Bear Swamp (3) |
- | - | 3 | 1 | 50.0 | |||||||||||||||
| $ | 638 | $ | 634 | $ | 21 | $ | 19 | |||||||||||||
(1) Emera has significant influence over the operating and financial decisions of these companies through Board representation and therefore, records its investment in these entities using the equity method.
(2) NSPI has a 50 per cent indirect voting interest in WTI. As of March 31, 2026, NSPI’s economic interest based on the $9 million invested is 26 per cent. WTI is a regulated utility, formed to develop and operate the Wasoqonatl transmission line project which will create a 160 kilometre, 345 kilovolt transmission reliability intertie between Nova Scotia and New Brunswick. WTI is wholly-owned by a limited partnership between NSPI, the Canada Infrastructure Bank, the Wskijinu’k Mtmo’taqnuow Agency and Mi’gmaq United Investment Network. NSPI is responsible for providing construction, operation, maintenance and administrative services to WTI.
(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $179 million distribution received in 2015. Bear Swamp’s credit investment balance of $83 million (2025 – $84 million) is recorded in “Other long-term liabilities” on the Condensed Consolidated Balance Sheets.
Emera accounts for its variable interest investment in NSPML as an equity investment (note 22). NSPML’s consolidated summarized balance sheet is as follows:
| As at millions of dollars |
March 31 2026 |
December 31 2025 |
||||||
| Current assets |
$ | 69 | $ | 40 | ||||
| PP&E |
1,367 | 1,380 | ||||||
| Regulatory assets |
781 | 782 | ||||||
| Non-current assets |
27 | 27 | ||||||
| Total assets |
$ |
2,244 |
|
$ |
2,229 |
| ||
| Current liabilities |
$ | 95 | $ | 87 | ||||
| Long-term debt (1) |
1,495 | 1,495 | ||||||
| Non-current liabilities |
190 | 185 | ||||||
| Equity |
464 | 462 | ||||||
| Total liabilities and equity |
$ |
2,244 |
|
$ |
2,229 |
| ||
(1) The project debt has been guaranteed by the Government of Canada.
16
8. INCOME TAXES
The income tax provision, for the three months ended March 31, differs from that computed using the enacted Canadian federal statutory income tax rate for the following reasons:
| millions of dollars | 2026 | 2025 | ||||||||||||||
| Income before provision for income taxes |
$ | 711 | $ | 720 | ||||||||||||
| Income taxes, at statutory income tax rate |
107 | 15% | 108 | 15% | ||||||||||||
| Domestic reconciling items: |
||||||||||||||||
| Investment tax credits |
(10) | (1)% | (26) | (4)% | ||||||||||||
| Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities |
(10) | (1)% | (14) | (2)% | ||||||||||||
| Net Part VI.1 tax |
8 | 1% | 4 | 1% | ||||||||||||
| Valuation allowance |
(3) | -% | (1) | -% | ||||||||||||
| Other |
(2) | -% | (1) | -% | ||||||||||||
| Provincial income taxes (1) |
35 | 4% | 43 | 6% | ||||||||||||
| Foreign reconciling items: | ||||||||||||||||
| United States |
||||||||||||||||
| Federal tax rate variance |
18 | 2% | 16 | 2% | ||||||||||||
| State income tax, net of federal income tax benefit |
13 | 2% | 12 | 2% | ||||||||||||
| Production tax credits |
(12) | (2)% | (9) | (1)% | ||||||||||||
| Amortization of deferred income tax regulatory liabilities |
(8) | (1)% | (9) | (1)% | ||||||||||||
| Deferral and amortization of Investment tax credits |
(5) | (1)% | 18 | 2% | ||||||||||||
| Investment tax credits |
- | -% | (21) | (3)% | ||||||||||||
| Other |
(1) | -% | (2) | -% | ||||||||||||
| Other foreign jurisdictions |
(1) | -% | 1 | -% | ||||||||||||
| Income tax expense |
$ | 129 | 18% | $ | 119 | 17% | ||||||||||
(1) The majority of provincial income taxes relate to Nova Scotia.
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, 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.
9. COMMON STOCK
Authorized: Unlimited number of non-par value common shares.
| 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 ECSPP |
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, which expires on January 5, 2029.
17
10. EARNINGS PER SHARE
The following table reconciles the computation of basic and diluted earnings per share:
| For the | Three months ended March 31 | |||||||
| millions of dollars (except per share amounts) | 2026 | 2025 | ||||||
| Numerator |
||||||||
| Net income attributable to common shareholders |
$ | 561.7 | $ | 583.4 | ||||
| Diluted numerator |
561.7 | 583.4 | ||||||
| Denominator |
||||||||
| Weighted average shares of common stock outstanding – basic |
$ | 303.3 | $ | 297.0 | ||||
| Stock-based compensation |
0.9 | 0.3 | ||||||
| Weighted average shares of common stock outstanding – diluted |
$ | 304.2 | $ | 297.3 | ||||
| Earnings per common share |
||||||||
| Basic |
$ | 1.85 | $ | 1.96 | ||||
| Diluted |
$ | 1.85 | $ | 1.96 | ||||
11. ACCUMULATED OTHER COMPREHENSIVE INCOME
The components of AOCI, net of tax, are as follows:
| millions of dollars | Unrealized (loss) gain on translation of self-sustaining foreign operations |
Net change in net investment hedges |
Gains (losses) on derivatives recognized as cash flow hedges |
Net change in available- for-sale |
Net change in unrecognized pension and post- retirement benefit costs |
Total AOCI |
||||||||||||||||||
| For the three months ended March 31, 2026 |
| |||||||||||||||||||||||
| Balance, January 1, 2026 |
$ | 773 | $ | (81) | $ | 10 | $ | 2 | $ | 169 | $ | 873 | ||||||||||||
| OCI before reclassifications |
230 | (28) | - | (1) | - | 201 | ||||||||||||||||||
| Amounts reclassified from AOCI |
- | - | - | - | (5) | (5) | ||||||||||||||||||
| Net current period OCI |
230 | (28) | - | (1) | (5) | 196 | ||||||||||||||||||
| Balance, March 31, 2026 |
$ | 1,003 | $ | (109) | $ | 10 | $ | 1 | $ | 164 | $ | 1,069 | ||||||||||||
| For the three months ended March 31, 2025 |
| |||||||||||||||||||||||
| Balance, January 1, 2025 |
$ | 1,396 | $ | (163) | $ | 12 | $ | - | $ | 16 | $ | 1,261 | ||||||||||||
| OCI before reclassifications |
(12) | 2 | - | - | - | (10) | ||||||||||||||||||
| Amounts reclassified from AOCI |
- | - | - | - | (4) | (4) | ||||||||||||||||||
| Net current period OCI |
(12) | 2 | - | - | (4) | (14) | ||||||||||||||||||
| Balance, March 31, 2025 |
$ | 1,384 | $ | (161) | $ | 12 | $ | - | $ | 12 | $ | 1,247 | ||||||||||||
The reclassifications out of AOCI are as follows:
| For the | Three months ended March 31 | |||||||||
| millions of dollars | 2026 | 2025 | ||||||||
| Affected line item in the Condensed Consolidated Financial Statements |
|
Amounts reclassified from AOCI |
| |||||||
| Net change in unrecognized pension and post-retirement benefit costs |
| |||||||||
| Amounts reclassified into obligations |
Pension and post-retirement benefits | (5) | (4) | |||||||
| Total reclassifications out of AOCI for the period |
$ | (5) | $ | (4) | ||||||
18
12. DERIVATIVE INSTRUMENTS
The Company enters into futures, forwards, swaps and option contracts as part of its risk management strategy to limit exposure to:
| ● | commodity price fluctuations related to the purchase and sale of commodities in the course of normal operations; |
| ● | foreign exchange (“FX”) fluctuations on foreign currency denominated purchases and sales; |
| ● | interest rate fluctuations on debt securities; and |
| ● | share price fluctuations on stock-based compensation. |
The Company also enters into physical contracts for energy commodities. Collectively, these contracts are considered “derivatives”. The Company accounts for derivatives under one of the following four approaches:
| 1. | Physical contracts that meet the normal purchases normal sales (“NPNS”) exemption are not recognized on the balance sheet; they are recognized in income when they settle. A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty credit worthy. The Company continually assesses contracts designated under the NPNS exemption and will discontinue treatment of these contracts under this exception if the criteria are no longer met. |
| 2. | Derivatives that qualify for hedge accounting are recorded at FV on the balance sheet. Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively hedge the identified cash flow risk both at the inception and over the term of the derivative. Specifically, for cash flow hedges, the change in the FV of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. |
| Where documentation or effectiveness requirements are not met, the derivatives are recognized at FV with any changes in FV recognized in net income in the reporting period, unless deferred as a result of regulatory accounting. |
| 3. | Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. These derivatives are recorded at FV on the balance sheet as derivative assets or liabilities. The change in FV of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes that any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates. Based on current direction from the FPSC, TEC and PGS have no derivatives related to hedging. |
| 4. | Derivatives that do not meet any of the above criteria are designated as held-for-trading (“HFT”) derivatives and are recorded on the balance sheet at FV, with changes normally recorded in net income of the period, unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply. |
19
Derivative assets and liabilities relating to the foregoing categories consisted of the following:
| Derivative Assets | Derivative Liabilities | |||||||||||||||
| As at | March 31 | December 31 | March 31 | December 31 | ||||||||||||
| millions of dollars | 2026 | 2025 | 2026 | 2025 | ||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
$ | 42 | $ | 22 | $ | 24 | $ | 33 | ||||||||
| FX forwards |
5 | 3 | - | 2 | ||||||||||||
| 47 | 25 | 24 | 35 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
34 | 51 | 31 | 50 | ||||||||||||
| Natural gas swaps, futures, forwards, physical contracts |
243 | 238 | 655 | 695 | ||||||||||||
| 277 | 289 | 686 | 745 | |||||||||||||
| Other derivatives: |
||||||||||||||||
| Equity derivatives |
22 | 8 | - | - | ||||||||||||
| FX forwards |
3 | 8 | 4 | 1 | ||||||||||||
| 25 | 16 | 4 | 1 | |||||||||||||
| Total gross derivatives |
349 | 330 | 714 | 781 | ||||||||||||
| Impact of master netting agreements: |
||||||||||||||||
| Regulatory deferral |
(1) | (1) | (1) | (1) | ||||||||||||
| HFT derivatives |
(92) | (131) | (92) | (131) | ||||||||||||
| Total impact of master netting agreements |
(93) | (132) | (93) | (132) | ||||||||||||
| Total derivatives |
$ | 256 | $ | 198 | $ | 621 | $ | 649 | ||||||||
| Current (1) |
215 | 156 | 526 | 534 | ||||||||||||
| Long-term (1) |
41 | 42 | 95 | 115 | ||||||||||||
| Total derivatives |
$ | 256 | $ | 198 | $ | 621 | $ | 649 | ||||||||
(1) Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.
Cash Flow Hedges
On May 26, 2021, a treasury lock was settled for a gain of $19 million that is being amortized through interest expense over 10 years as the underlying hedged item settles. As of March 31, 2026, the unrealized gain in AOCI was $10 million, after-tax (December 31, 2025 – $10 million, after-tax). The Company expects $2 million of unrealized gains currently in AOCI to be reclassified into net income within the next twelve months.
Regulatory Deferral
The Company has recorded the following changes with respect to derivatives receiving regulatory deferral:
| millions of dollars |
Commodity swaps and forwards |
FX forwards |
Commodity swaps and forwards |
FX forwards |
||||||||||||
| For the three months ended March 31 | 2026 | 2025 | ||||||||||||||
| Unrealized gain (loss) in regulatory assets |
$ | - | $ | 3 | $ | (10 | ) | $ | 5 | |||||||
| Unrealized gain (loss) in regulatory liabilities |
35 | 1 | 20 | (4 | ) | |||||||||||
| Realized (gain) loss in regulatory assets |
(1 | ) | - | (1 | ) | - | ||||||||||
| Realized (gain) loss in regulatory liabilities |
(1 | ) | - | 2 | - | |||||||||||
| Realized (gain) loss in property, plant and equipment |
(7 | ) | - | - | - | |||||||||||
| Realized (gain) loss in inventory (1) |
2 | - | 3 | (4 | ) | |||||||||||
| Realized (gain) loss in regulated fuel for generation and purchased power (2) |
1 | - | 1 | - | ||||||||||||
| Other |
- | - | - | (2 | ) | |||||||||||
| Total change in derivative instruments |
$ | 29 | $ | 4 | $ | 15 | $ | (5 | ) | |||||||
(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.
(2) Realized (gains) losses on derivative instruments settled and consumed in the period and hedging relationships that have been terminated or the hedged transaction is no longer probable.
20
As at March 31, 2026, the Company had the following notional volumes designated for regulatory deferral that are expected to settle as outlined below:
| millions | 2026 | 2027-2028 | ||||||
| Commodity swaps and forwards purchases: |
||||||||
| Natural gas (MMBtu) |
5 | 7 | ||||||
| Power (MWh) |
1 | 1 | ||||||
| FX forwards: |
||||||||
| FX contracts (millions of USD) |
$ | 140 | $ | 92 | ||||
| Weighted average rate |
1.3527 | 1.3522 | ||||||
| % of USD requirements |
66% | 20% | ||||||
HFT Derivatives
The Company has recognized the following realized and unrealized gains with respect to HFT derivatives:
| For the | Three months ended March 31 | |||||||
| millions of dollars | 2026 | 2025 | ||||||
| Power swaps and physical contracts in non-regulated operating revenues | $ | 2 | $ | - | ||||
| Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues | 339 | 466 | ||||||
| Total gains in net income |
$ | 341 | $ | 466 | ||||
As at March 31, 2026, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:
| millions | 2026 | 2027 | 2028 | 2029 | 2030 and thereafter |
|||||||||||||||
| Natural gas purchases (MMBtu) |
452 | 154 | 53 | 31 | 47 | |||||||||||||||
| Natural gas sales (MMBtu) |
473 | 143 | 24 | 11 | 7 | |||||||||||||||
| Power purchases (MWh) |
2 | - | - | - | - | |||||||||||||||
| Power sales (MWh) |
2 | 1 | - | - | - | |||||||||||||||
Other Derivatives
As at March 31, 2026, the Company had equity derivatives in place to manage cash flow risk associated with forecasted future cash settlements of deferred compensation obligations and FX forwards in place to manage cash flow risk associated with forecasted USD cash inflows. The equity derivatives hedge the return on 3.2 million shares and extends until December of 2026. The FX forwards have a combined notional amount of $323 million USD and expire in 2026 through 2028.
| For the | Three months ended March 31 | |||||||||||||||
| millions of dollars | 2026 | 2025 | ||||||||||||||
| FX forwards |
Equity derivatives |
FX forwards |
Equity derivatives |
|||||||||||||
| Unrealized gain (loss) in OM&G | $ | - | $ | 22 | $ | - | $ | 20 | ||||||||
| Unrealized gain (loss) in other income, net | (7) | - | 4 | - | ||||||||||||
| Realized loss in other income, net | - | - | (8) | - | ||||||||||||
| Total gains (losses) in net income | $ | (7) | $ | 22 | $ | (4) | $ | 20 | ||||||||
Credit Risk
The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits, and derivative assets. Credit risk is the potential loss from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral are requested on any high-risk accounts.
21
The Company assesses the potential for credit losses on a regular basis and, where appropriate, maintains provisions. With respect to counterparties, the Company has implemented procedures to monitor the creditworthiness and credit exposure of counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in default probability rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the Company’s current default probability. Net asset positions are adjusted based on the counterparty’s current default probability. The Company assesses credit risk internally for counterparties that are not rated.
It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, FX and interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit to the Company for the value in excess of the credit limit where contractually required. The Company also obtains cash deposits from electric customers. The Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer required by the Company.
The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk to these counterparties. The Company generally enters into International Swaps and Derivatives Association agreements, North American Energy Standards Board agreements and/or Edison Electric Institute agreements. The Company believes entering into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance and default.
As at March 31, 2026, the Company had $244 million (December 31, 2025 – $207 million) in financial assets considered to be past due, which had been outstanding for an average 76 days. The FV of these financial assets was $228 million (December 31, 2025 – $192 million), the difference of which is included in the allowance for credit losses. These assets primarily relate to accounts receivable from electric and gas revenue.
Cash Collateral
The Company’s cash collateral positions consisted of the following:
| As at millions of dollars |
March 31 2026 |
December 31 2025 |
||||||
| Cash collateral provided to others |
$ | 254 | $ | 193 | ||||
| Cash collateral received from others |
$ | 4 | $ | 5 | ||||
Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured credit rating as determined by certain major credit rating agencies. Certain derivatives contain financial assurance provisions that require collateral to be posted if a material adverse credit-related event occurs. If a material adverse event resulted in the senior unsecured debt falling below investment grade, the counterparties to such derivatives could request ongoing full collateralization.
As at March 31, 2026, the total FV of derivatives in a liability position was $621 million (December 31, 2025 – $649 million). If the credit ratings of the Company were reduced below investment grade, the full value of the net liability position could be required to be posted as collateral for these derivatives.
22
13. FV MEASUREMENTS
The Company is required to determine the FV of all derivatives except those which qualify for the NPNS exemption (see note 12) and uses a market approach to do so. The three levels of the FV hierarchy are defined as follows:
Level 1 – Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets (“quoted prices”) for identical assets and liabilities.
Level 2 – Where quoted prices for identical assets and liabilities are not available, the valuation of certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing houses.
Level 3 – Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally developed inputs. The primary reasons for a Level 3 classification are as follows:
| ● | While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials. |
| ● | The term of certain transactions extends beyond the period when quoted prices are available, and accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term. |
| ● | The valuations of certain transactions were based on internal models, although quoted prices were utilized in the valuations. |
Derivative assets and liabilities are classified in their entirety, based on the lowest level of input that is significant to the FV measurement.
23
The following tables set out the classification of the methodology used by the Company to FV its derivatives:
| As at | March 31, 2026 | |||||||||||||||
| millions of dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Assets |
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
$ | 26 | $ | 15 | $ | - | $ | 41 | ||||||||
| FX forwards |
- | 5 | - | 5 | ||||||||||||
| 26 | 20 | - | 46 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
- | 16 | 6 | 22 | ||||||||||||
| Natural gas swaps, futures, forwards, physical contracts and related transportation |
2 | 148 | 13 | 163 | ||||||||||||
| 2 | 164 | 19 | 185 | |||||||||||||
| Other derivatives: |
||||||||||||||||
| FX forwards |
- | 3 | - | 3 | ||||||||||||
| Equity derivatives |
22 | - | - | 22 | ||||||||||||
| 22 | 3 | - | 25 | |||||||||||||
| Total assets |
50 | 187 | 19 | 256 | ||||||||||||
| Liabilities |
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
18 | 5 | - | 23 | ||||||||||||
| 18 | 5 | - | 23 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
- | 16 | 4 | 20 | ||||||||||||
| Natural gas swaps, futures, forwards and physical contracts |
22 | 263 | 289 | 574 | ||||||||||||
| 22 | 279 | 293 | 594 | |||||||||||||
| Other derivatives: |
||||||||||||||||
| FX forwards |
- | 4 | - | 4 | ||||||||||||
| - | 4 | - | 4 | |||||||||||||
| Total liabilities |
40 | 288 | 293 | 621 | ||||||||||||
| Net assets (liabilities) |
$ | 10 | $ | (101) | $ | (274) | $ | (365) | ||||||||
24
| As at | December 31, 2025 | |||||||||||||||
| millions of dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Assets |
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
$ | 21 | $ | - | $ | - | $ | 21 | ||||||||
| FX forwards |
- | 3 | - | 3 | ||||||||||||
| 21 | 3 | - | 24 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
(1) | 29 | 7 | 35 | ||||||||||||
| Natural gas swaps, futures, forwards, physical contracts and related transportation |
1 | 88 | 34 | 123 | ||||||||||||
| - | 117 | 41 | 158 | |||||||||||||
| Other derivatives: |
||||||||||||||||
| FX forwards |
- | 8 | - | 8 | ||||||||||||
| Equity derivatives |
8 | - | - | 8 | ||||||||||||
| 8 | 8 | - | 16 | |||||||||||||
| Total assets |
29 | 128 | 41 | 198 | ||||||||||||
| Liabilities |
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
11 | 21 | - | 32 | ||||||||||||
| FX forwards |
- | 2 | - | 2 | ||||||||||||
| 11 | 23 | - | 34 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
(4) | 31 | 7 | 34 | ||||||||||||
| Natural gas swaps, futures, forwards and physical contracts |
1 | 115 | 464 | 580 | ||||||||||||
| (3) | 146 | 471 | 614 | |||||||||||||
| Other derivatives: |
||||||||||||||||
| FX forwards |
- | 1 | - | 1 | ||||||||||||
| - | 1 | - | 1 | |||||||||||||
| Total liabilities |
8 | 170 | 471 | 649 | ||||||||||||
| Net assets (liabilities) |
$ | 21 | $ | (42) | $ | (430) | $ | (451) | ||||||||
The change in the FV of the Level 3 financial assets and liabilities for the three months ended March 31, 2026 was as follows:
|
HFT Derivatives |
||||||||||||
| millions of dollars | Power | Natural gas | Total | |||||||||
| Assets |
||||||||||||
| Balance, beginning of period |
$ | 7 | $ | 34 | $ | 41 | ||||||
| Total realized and unrealized losses included in non-regulated operating revenues | (1) | (21) | (22) | |||||||||
| Balance, March 31, 2026 |
$ | 6 | $ | 13 | $ | 19 | ||||||
| Liabilities |
||||||||||||
| Balance, beginning of period |
$ | 7 | $ | 464 | $ | 471 | ||||||
| Total realized and unrealized losses included in non-regulated operating revenues | (3) | (175) | (178) | |||||||||
| Balance, March 31, 2026 |
$ | 4 | $ | 289 | $ | 293 | ||||||
Significant unobservable inputs used in the FV measurement of Emera’s natural gas and power derivatives include third-party sourced pricing for instruments based on illiquid markets. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) FV measurement. Other unobservable inputs used include internally developed correlation factors and basis differentials; own credit risk; and discount rates. Internally developed correlations and basis differentials are reviewed on a quarterly basis based on statistical analysis of the spot markets in the various illiquid term markets. Discount rates may include a risk premium for those long-term forward contracts with illiquid future price points to incorporate the inherent uncertainty of these points. Any risk premiums for long-term contracts are evaluated by observing similar industry practices and in discussion with industry peers.
25
The Company uses a modelled pricing valuation technique for determining the FV of Level 3 derivative instruments. The following table outlines quantitative information about the significant unobservable inputs used in the FV measurements categorized within Level 3 of the FV hierarchy:
| March 31, 2026 | ||||||||||||||||||||||
| As at millions of dollars |
FV | Significant Unobservable Input |
Low | High | Weighted Average (1) |
|||||||||||||||||
| Assets | Liabilities | |||||||||||||||||||||
| HFT derivatives – Power swaps and physical contracts | 6 | 4 | Third-party pricing | $ | 23.50 | $ | 188.35 | $89.66 | ||||||||||||||
| HFT derivatives – Natural gas swaps, futures, forwards and physical contracts | 13 | 289 | Third-party pricing | $2.06 | $23.14 | $14.47 | ||||||||||||||||
| Total |
$ | 19 | $ | 293 | ||||||||||||||||||
| Net liability |
$ | 274 | ||||||||||||||||||||
(1) Unobservable inputs were weighted by the relative FV of the instruments.
Long-term debt is a financial liability not measured at FV on the Condensed Consolidated Balance Sheets. The balance consisted of the following:
| As at millions of dollars |
Carrying Amount |
FV | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||
| March 31, 2026 |
$ | 22,460 | $ | 21,495 | $ | - | $ | 21,116 | $ | 379 | $ | 21,495 | ||||||||||||
| December 31, 2025 |
$ | 19,654 | $ | 18,956 | $ | - | $ | 18,535 | $ | 421 | $ | 18,956 | ||||||||||||
The Company has designated $1.2 billion USD denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in USD denominated operations. An after-tax foreign currency loss of $28 million was recorded in AOCI for the three months ended March 31, 2026 (2025 – $2 million gain after-tax).
14. RELATED PARTY TRANSACTIONS
In the ordinary course of business, Emera provides energy and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Intercompany balances and intercompany transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities, in accordance with accounting standards for rate-regulated entities. All material amounts are under normal interest and credit terms.
Significant transactions between Emera and its associated companies are as follows:
| ● | Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Condensed Consolidated Statements of Income. NSPI’s expense is reported in “Regulated fuel for generation and purchased power”, totalling $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”. |
| ● | 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.
26
15. RECEIVABLES AND OTHER CURRENT ASSETS
| As at millions of dollars |
March 31 2026 |
December 31 2025 |
||||||
|
|
||||||||
| Customer accounts receivable – billed |
$ 1,110 | $ 1,265 | ||||||
|
|
||||||||
| Customer accounts receivable – unbilled |
409 | 400 | ||||||
|
|
||||||||
| Capitalized transportation capacity (1) |
422 | 238 | ||||||
|
|
||||||||
| Cash collateral provided to others |
254 | 193 | ||||||
|
|
||||||||
| Prepaid expenses |
124 | 105 | ||||||
|
|
||||||||
| Sales tax receivable |
90 | 84 | ||||||
|
|
||||||||
| Income tax receivable |
29 | 19 | ||||||
|
|
||||||||
| Allowance for credit losses |
(16) | (15) | ||||||
|
|
||||||||
| Other |
159 | 150 | ||||||
|
|
||||||||
| Total receivables and other current assets |
$ 2,581 | $ 2,439 | ||||||
|
|
||||||||
(1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract.
16. EMPLOYEE BENEFIT PLANS
Emera maintains a number of contributory defined-benefit (“DB”) and defined-contribution (“DC”) pension plans, which cover substantially all of its employees. The Company also provides non-pension benefits for its retirees.
Emera’s net periodic benefit cost included the following:
| For the | Three months ended March 31 | |||||||
| millions of dollars | 2026 | 2025 | ||||||
|
|
||||||||
| DB pension plans |
||||||||
| Service cost |
$ | 9 | $ | 9 | ||||
|
|
||||||||
| Non-service cost: |
||||||||
| Interest cost |
28 | 29 | ||||||
|
|
||||||||
| Expected return on plan assets |
(39) | (41) | ||||||
|
|
||||||||
| Current year amortization of actuarial losses |
1 | - | ||||||
| Current year amortization of regulatory asset |
4 | 3 | ||||||
|
|
||||||||
| Total non-service costs |
(6) | (9) | ||||||
|
|
||||||||
| Total DB pension plans |
3 | - | ||||||
|
|
||||||||
| Non-pension benefits plan |
| |||||||
| Service cost |
1 | 1 | ||||||
|
|
||||||||
| Non-service cost: |
| |||||||
| Interest cost |
3 | 3 | ||||||
|
|
||||||||
| Expected return on plan assets |
(1) | (1) | ||||||
|
|
||||||||
| Current year amortization of actuarial gains |
(1) | - | ||||||
|
|
||||||||
| Total non-service costs |
1 | 2 | ||||||
|
|
||||||||
| Total non-pension benefits plans |
2 | 3 | ||||||
|
|
||||||||
| Total DB pension and non-pension plans |
$ | 5 | $ | 3 | ||||
|
|
||||||||
Emera’s contributions related to these DB pension plans for the three months ended March 31, 2026 were $13 million (2025 – $13 million). Annual employer cash contributions to the DB pension plans are estimated to be $34 million for 2026. Emera’s cash contributions related to these DC pension plans for the three months ended March 31, 2026 were $11 million (2025 – $13 million).
27
17. SHORT-TERM DEBT
Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non-revolving credit facilities and short-term notes. For details regarding short-term debt, refer to note 24 in Emera’s 2025 annual audited consolidated financial statements, and below for 2026 short-term debt financing activity.
Recent financing activity is discussed below:
Other
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.
18. LONG-TERM DEBT
For details regarding long-term debt, refer to note 26 in Emera’s 2025 annual audited consolidated financial statements, and below for 2026 long-term debt financing activity.
Recent financing activities 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.
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.
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.
28
Other
On March 4, 2026, EUSHI Finance, Emera Finance, 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.
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.
29
19. COMMITMENTS AND CONTINGENCIES
A. Commitments
As at March 31, 2026, contractual commitments (excluding pensions and other post-retirement obligations, long-term debt and asset retirement obligations) for each of the next five years and in aggregate thereafter consisted of the following:
| millions of dollars | 2026 | 2027 | 2028 | 2029 | 2030 | Thereafter | Total | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Purchased power (1) |
$ | 308 | $ | 421 | $ | 410 | $ | 457 | $ | 450 | $ | 5,921 | $ | 7,967 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
| Transportation (2)(3) |
736 | 701 | 536 | 459 | 396 | 3,049 | 5,877 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Fuel, gas supply and storage (4) |
563 | 288 | 189 | 195 | 81 | 61 | 1,377 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Capital projects |
261 | 76 | 47 | 4 | - | - | 388 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other |
127 | 76 | 56 | 55 | 47 | 314 | 675 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| $ | 1,995 | $ | 1,562 | $ | 1,238 | $ | 1,170 | $ | 974 | $ | 9,345 | $ | 16,284 | |||||||||||||||
|
|
||||||||||||||||||||||||||||
As detailed below, commitments at March 31, 2026 include those related to NMGC. On completion of the sale of NMGC, all remaining future commitments will be transferred to the buyer. For further details on the pending transaction, refer to note 3.
(1) Annual requirement to purchase electricity from Independent Power Producers or other utilities over varying contract lengths.
(2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $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.
(3) 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).
(4) Includes $253 million related to NMGC (2026: $75 million, 2027: $51 million, 2028: $44 million, 2029: $41 million, 2030: $41 million).
NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. 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.
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.
B. Legal Proceedings
Superfund and Former Manufactured Gas Plant Sites
Previously, TEC had been a potentially responsible party (“PRP”) for certain superfund sites through its Tampa Electric and former PGS divisions, as well as for certain former manufactured gas plant sites through its PGS division. As a result of the separation of the PGS division into a separate legal entity, Peoples Gas System, Inc. is also now a PRP for those sites (in addition to third party PRPs for certain sites). While the aggregate joint and several liability associated with these sites has not changed as a result of the PGS legal separation, the sites continue to present the potential for significant response costs. As at March 31, 2026, the aggregate financial liability of the Florida utilities is estimated to be $15 million ($11 million USD), primarily at PGS. This estimate assumes that other involved PRPs are credit-worthy entities. This amount has been accrued and is primarily reflected in the long-term liability section under “Other long-term liabilities” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.
The estimated amounts represent only the portion of cleanup costs attributable to the Florida utilities. The estimates to perform the work are based on the Florida utilities’ experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.
30
In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-worthy and are likely to continue to be credit-worthy for the duration of remediation work. However, in those instances that they are not, the Florida utilities could be liable for more than their actual percentage of remediation costs. Other factors that could impact these estimates include additional testing and investigation which could expand the scope of cleanup activities, additional liability that might arise from cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in base rate proceedings.
Other Legal Proceedings
Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company.
C. Principal Financial Risks and Uncertainties
For information on principal financial risks which could materially affect the Company in the normal course of business, refer to note 28 in Emera’s 2025 annual audited consolidated financial statements. Risks associated with derivative instruments and FV measurements are discussed in note 12 and note 13. There have been no material changes to the principal financial risks as of March 31, 2026.
D. Guarantees and Letters of Credit
Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2025 audited annual consolidated financial statements, 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.
20. CUMULATIVE PREFERRED STOCK
For details regarding cumulative preferred stock, refer to note 29 in Emera’s 2025 annual audited consolidated financial statements, and below for 2026 preferred stock activity.
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”). There are currently 8.0 million Series J Shares outstanding.
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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21. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
| For the | Three months ended March 31 | |||||||
| millions of dollars | 2026 | 2025 | ||||||
|
|
||||||||
| Changes in non-cash working capital: |
||||||||
| Inventory |
$ | 23 | $ | 25 | ||||
|
|
||||||||
| Receivables and other current assets |
107 | (40) | ||||||
|
|
||||||||
| Accounts payable |
(315) | (151) | ||||||
|
|
||||||||
| Other current liabilities |
145 | 132 | ||||||
|
|
||||||||
| Total non-cash working capital |
$ | (40) | $ | (34) | ||||
|
|
||||||||
| Supplemental disclosure of non-cash activities: |
||||||||
| Common share dividends reinvested |
$ | 71 | $ | 76 | ||||
|
|
||||||||
| Increase (decrease) in accrued capital expenditures |
$ | 65 | $ | (83) | ||||
|
|
||||||||
| Accrued long-term debt issuance costs |
$ | 7 | $ | - | ||||
|
|
||||||||
| Reclassification of short-term debt to long-term debt |
$ | 209 | $ | - | ||||
|
|
||||||||
| Supplemental disclosure of operating activities: |
||||||||
| Net change in short-term regulatory assets and liabilities |
$ | 21 | $ | 93 | ||||
|
|
||||||||
22. VARIABLE INTEREST ENTITIES
Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since it does not have controlling financial interest of NSPML. When the critical milestones were achieved, NLH was deemed the primary beneficiary of the asset for financial reporting purposes as it has authority over the majority of the direct activities expected to most significantly impact the economic performance of the Maritime Link. Thus, Emera began recording the Maritime Link as an equity investment.
BLPC established a SIF, primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission and distribution systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered that, in substance, activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. Any withdrawal of SIF fund assets by the Company would be subject to existing regulations. Emera’s consolidated VIE in the SIF is recorded as an “Other long-term assets”, “Restricted cash” and “Regulatory liabilities” on the Condensed Consolidated Balance Sheets. Amounts included in restricted cash represent the cash portion of funds required to be set aside for the BLPC SIF.
The Company has identified certain long-term purchase power agreements that meet the definition of variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions.
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The following table provides information about Emera’s portion of material unconsolidated VIEs:
| As at | March 31, 2026 | December 31, 2025 | ||||||||||||||
|
|
||||||||||||||||
| millions of dollars | Total assets |
Maximum exposure to loss |
Total assets |
Maximum exposure to loss |
||||||||||||
|
|
||||||||||||||||
| Unconsolidated VIEs in which Emera has variable interests |
||||||||||||||||
| NSPML (equity accounted) |
$ | 464 | $ | 6 | $ | 462 | $ | 6 | ||||||||
|
|
||||||||||||||||
23. SUBSEQUENT EVENTS
These unaudited condensed consolidated interim financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through May 8, 2026, the date the unaudited condensed consolidated interim financial statements were issued.
33
Exhibit 99.3
Emera Incorporated
Earnings Coverage Ratio
Pursuant to Section 8.4 of National Instrument 44-102, this updated calculation of the earnings coverage ratio is filed as an exhibit to the unaudited condensed consolidated interim financial statements of Emera Incorporated (“Emera”) for three months ended March 31, 2026.
The following earnings coverage ratio is calculated on a consolidated basis for twelve months ended March 31, 2026.
| Twelve months ended March 31, 2026 | ||
| Earnings Coverage (1) |
1.86 |
(1) Earnings coverage is equal to consolidated net income attributable to common shareholders plus: income taxes, interest on debt, amortization of debt financing costs, allowance for funds used during construction and preferred share dividends declared during the period together with undeclared preferred share dividends, if any, divided by the sum of interest on debt, amortization of debt financing costs, allowance for funds used during construction, capitalized interest and preferred dividends grossed up to a before-tax equivalent using an effective tax rate of 29.0 per cent.
Emera’s dividend requirements on all of its preferred shares, grossed up to a before-tax equivalent using an effective income tax rate of 29.0 per cent, amounted to $109 million for twelve months ended March 31, 2026. Emera’s interest requirements for twelve months ended March 31, 2026 amounted to $1,076 million. Emera’s consolidated income before interest and income tax for twelve months ended March 31, 2026 was $2,210 million, which is 1.86 times Emera’s aggregate preferred dividends and interest requirements for this period.
Exhibit 99.4
Emera Reports 2026 First Quarter Financial Results
HALIFAX, Nova Scotia – Today, May 8, 2026, Emera Inc. (“Emera”) (TSX/NYSE: EMA) reported 2026 first quarter financial results1.
Highlights
| • | Delivered a 7% increase in adjusted earnings per share2 (“EPS”), with $1.37 in Q1 2026, compared to $1.28 in Q1 2025, and reported EPS of $1.85 compared to $1.96 in Q1 2025. |
| • | On track to deliver 2026 adjusted EPS2 growth above our earnings guidance range of 5-7%3 annualized. |
| • | Capital plan on track: Deployed more than $870 million of our $4.0 billion 2026 capital plan. |
| • | Delivered a 6% increase to operating cash flow compared to Q1 2025. |
| • | Emera entered into an agreement to sell its 100% interest in Grand Bahama Power Company. |
“Emera delivered a solid first quarter, with important regulatory outcomes, disciplined capital deployment and record results at Emera Energy, contributing to our strong start,” said Scott Balfour, President and CEO of Emera Inc. “This performance furthers our confidence in delivering 5–7% average adjusted EPS² growth through 2030³ and positions us to exceed that range in 2026. Across our portfolio, our investments remain focused on reliability and managing cost impacts for customers.”
Q1 2026 Financial Results
Q1 2026 adjusted net income attributable to common shareholders (“adjusted net income”)2 was $415 million, or $1.37 per common share, compared to $379 million, or $1.28 per common share, in Q1 2025. The increase was primarily due to higher earnings from Emera Energy Services (“EES”), Peoples Gas Systems, Inc. (“PGS”) and Tampa Electric Company (“TEC”). These were partially offset by lower earnings from Nova Scotia Power Inc. (“NSPI”), the impact of a stronger Canadian dollar (“CAD”) and higher corporate costs.
Q1 2026 reported net income was $562 million, or $1.85 per common share, compared to net income of $583 million, or $1.96 per common share, in Q1 2025.
In Q1 2026, the translation impacts of a stronger CAD on USD denominated earnings decreased adjusted net income2 by $17 million and decreased reported net income by $30 million, compared to the same period in 2025. These impacts include the effect of FX hedges
1
used to mitigate translation risk of USD earnings, which are included in Corporate in the Other segment.
| (1) | Financial information is presented in CAD unless otherwise specified. |
| (2) | See “Non-GAAP Financial Measures and Ratios” noted below and “Segment Results and Non-GAAP Reconciliation” below for reconciliation to nearest USGAAP measure. |
| (3) | Adjusted EPS growth guidance uses 2024 as base year. |
Segment Results and Non-GAAP Reconciliation
| For the | Three months ended March 31 | |||||||
| millions of Canadian dollars (except per share amounts) | 2026 | 2025 | ||||||
| Adjusted net income1,2 |
||||||||
| Florida Electric Utility |
$ | 180 | $ | 164 | ||||
| Canadian Electric Utilities |
86 | 121 | ||||||
| Gas Utilities and Infrastructure |
136 | 120 | ||||||
| Other Electric Utilities |
8 | - | ||||||
| Other3 |
5 | (26) | ||||||
|
|
||||||||
| Adjusted net income1,2 |
$ | 415 | $ | 379 | ||||
|
|
||||||||
| MTM gain, after-tax4, |
147 | 204 | ||||||
|
|
||||||||
| Net income attributable to common shareholders |
$ | 562 | $ | 583 | ||||
|
|
||||||||
| EPS (basic) |
$ | 1.85 | $ | 1.96 | ||||
|
|
||||||||
| Adjusted EPS (basic)1,2 |
$ | 1.37 | $ | 1.28 | ||||
|
|
||||||||
1 See “Non-GAAP Financial Measures and Ratios” noted below.
2 Excludes the effect of Mark-to-Market (“MTM”) adjustments.
3 Higher earnings, quarter-over-quarter, primarily due to higher contributions from EES and increased income tax recovery at corporate, partially offset by increased corporate OM&G and interest expense.
4 Net of income tax expense of $61 million for the three months ended March 31, 2026 (2025 - $84 million tax expense).
Consolidated Financial Review
The following table highlights significant changes in adjusted net income from 2025 to 2026.
| For the millions of Canadian dollars |
Three months ended March 31 |
|||
| Adjusted net income – 20251,2 |
$ 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 | |||
2
| 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 investment tax credits in 2025 ($16 million) and 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 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 – 20261,2 | $ 415 |
1 See “Non-GAAP Financial Measures and Ratios” noted below and “Segment Results and Non-GAAP Reconciliation” for reconciliation to nearest US GAAP measure.
2 Excludes the effect of MTM adjustments, net of tax.
1Non-GAAP Financial Measures and Ratios
Emera uses financial measures that do not have standardized meaning under USGAAP and may not be comparable to similar measures presented by other entities. Emera calculates the non-GAAP measures and ratios by adjusting certain GAAP measures for specific items. Management believes excluding these items better distinguishes the ongoing operations of the business. For further information on the non-GAAP financial measure, adjusted net income, and the non-GAAP ratio, adjusted EPS – basic, refer to the “Non-GAAP Financial Measures and Ratios” section of Emera’s Q1 2026 MD&A, which is incorporated herein by reference and can be found on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov. Reconciliation to the nearest GAAP measure is included in “Segment Results and Non-GAAP Reconciliation” above.
3
Forward-Looking Information
This news release 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 U.S. Private Securities Litigation Reform Act of 1995 (collectively, “forward-looking information”) with respect to Emera, including without limitation, statements about the Company’s expectations regarding future growth, including plans to target an average adjusted EPS1 growth rate of 5 to 7 per cent through 2030 and expectations to exceed that range in 2026; the Company’s capital plans being on track for 2026; the Company’s ongoing focus on reliability and managing customer cost impacts; and its plans to sell GBPC. By its nature, forward-looking information requires Emera to make assumptions and is subject to inherent risks and uncertainties. These statements reflect Emera management’s current beliefs and are based on information currently available to Emera management. There is a risk that predictions, forecasts, conclusions and projections that constitute forward-looking information will not prove to be accurate, that Emera’s assumptions may not be correct and that actual results may differ materially from those expressed or implied by such forward-looking information. The forward-looking information in this news release is made only as of the date of thereof, and except as required by law, Emera disclaims any intention or obligation to update or revise any forward-looking information as a result of new information, future events or otherwise. Additional detailed information about these assumptions, risks and uncertainties is included in Emera’s securities regulatory filings, including under the heading “Enterprise Risk and Risk Management” in Emera’s annual Management’s Discussion and Analysis, and under the heading “Principal Financial Risks and Uncertainties” in the notes to Emera’s annual and interim financial statements, which can be found on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov.
Teleconference Call
The company will be hosting a teleconference today, Friday, May 8, 2026, at 9:30 a.m. Atlantic (8:30 a.m. Eastern) to discuss the Q1 2026 financial results.
Analysts and other interested parties in North America are invited to participate by dialing 1-800-717-1738. International parties are invited to participate by dialing 1-289-514-5100. Participants should dial in at least 10 minutes prior to the start of the call. No pass code is required.
A live and archived audio webcast of the teleconference will be available on the Company’s website, www.emera.com. A replay of the teleconference will be available on the Company’s website two hours after the conclusion of the call.
4
About Emera
Emera (TSX/NYSE: EMA) is a leading North American provider of energy services headquartered in Halifax, Nova Scotia, with investments in regulated electric and natural gas utilities, and related businesses and assets. The Emera family of companies delivers safe, reliable energy to approximately 2.7 million customers in the United States, Canada and the Caribbean. Our team of 7,800 employees is committed to our purpose of energizing modern life and delivering a cleaner energy future for all. Emera’s common and preferred shares are listed and trade on the Toronto Stock Exchange and its common shares are listed and trade on the New York Stock Exchange. Additional information can be accessed at www.emera.com, on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov.
Emera Inc.
Investor Relations
Dave Bezanson, SVP, Capital Markets
902-233-2674
dave.bezanson@emera.com
Emera Inc.
Media
Emera Corporate Communications
media@emera.com
5
Exhibit 99.5
FORM 52-109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE
I, Scott Balfour, President and Chief Executive Officer of Emera Incorporated, certify the following:
1. Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Emera Incorporated (the “issuer”) for the interim period ended March 31, 2026.
2. No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.
3. Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.
4. Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.
5. Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings
| A. | designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that |
| i. | material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and |
| ii. | information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and |
| B. | designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP. |
5.1 Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (COSO) Internal Control-Integrated Framework.
5.2 ICFR – material weakness relating to design: N/A
5.3 Limitation on scope of design: The issuer has disclosed in its interim MD&A
| a. | the fact that the issuer’s other certifying officer(s) and I have limited the scope of our design of DC&P and ICFR to exclude controls, policies and procedures of: |
| i. | a proportionately consolidated entity in which the issuer has an interest; |
| ii. | a special purpose entity in which the issuer has an interest; or |
| iii. | a business that the issuer acquired not more than 365 days before the last day of the period covered by the interim filings; and |
| b. | summary financial information about the proportionately consolidated entity, special purpose entity or business that the issuer acquired that has been proportionately consolidated or consolidated in the issuer’s financial statements. |
6. Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on January 1, 2026 and ended on March 31, 2026 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.
Date: May 8, 2026
| “Scott Balfour” |
| Scott Balfour |
| President and Chief Executive Officer |
Exhibit 99.6
FORM 52-109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE
I, Jared Green, Chief Financial Officer of Emera Incorporated, certify the following:
1. Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Emera Incorporated (the “issuer”) for the interim period ended March 31, 2026.
2. No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.
3. Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.
4. Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.
5. Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings
| A. | designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that |
| i. | material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and |
| ii. | information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and |
| B. | designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP. |
5.1 Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (COSO) Internal Control-Integrated Framework.
5.2 ICFR – material weakness relating to design: N/A
5.3 Limitation on scope of design: The issuer has disclosed in its interim MD&A
| a. | the fact that the issuer’s other certifying officer(s) and I have limited the scope of our design of DC&P and ICFR to exclude controls, policies and procedures of: |
| i. | a proportionately consolidated entity in which the issuer has an interest; |
| ii. | a special purpose entity in which the issuer has an interest; or |
| iii. | a business that the issuer acquired not more than 365 days before the last day of the period covered by the interim filings; and |
| b. | summary financial information about the proportionately consolidated entity, special purpose entity or business that the issuer acquired that has been proportionately consolidated or consolidated in the issuer’s financial statements. |
6. Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on January 1, 2026 and ended on March 31, 2026 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.
Date: May 8, 2026
| “Jared Green” |
| Jared Green |
| Chief Financial Officer |