Emera Inc 6-K, filed Nov 10, 2025
Emera Inc (EMA)
About this 6-K
Emera Inc filed this 6-K on November 10, 2025.
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 November, 2025
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, 99.2, 99.3, 99.4, 99.5 and 99.6 of this Form 6-K shall be incorporated by reference into the registration statement of Emera Incorporated on Form 40-F (File No. 001-42631).
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: November 7, 2025 | By: | /s/ Brian Curry | ||||
| Name: Brian Curry Title: Corporate Secretary | ||||||
EXHIBIT INDEX
Exhibit 99.1
Management’s Discussion & Analysis
As at November 7, 2025
Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its consolidated subsidiaries and investments (collectively referred to as “Emera” or the “Company”) during the third quarter of, and year-to-date, 2025 relative to the same periods in 2024; and its financial position as at September 30, 2025 relative to December 31, 2024. The Company’s activities are carried out through five reportable segments: Florida Electric Utility, Canadian Electric Utilities, Gas Utilities and Infrastructure, Other Electric Utilities, and Other.
This MD&A should be read in conjunction with the Emera unaudited condensed consolidated interim financial statements and supporting notes as at and for the three and nine months ended September 30, 2025; and the Emera annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2024. Emera follows United States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”). Additional information related to Emera, including the Company’s Annual Information Form, can be found on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov.
The accounting policies used by Emera’s rate-regulated entities may differ from those used by Emera’s non-rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities, revenues and expenses. At September 30, 2025, Emera’s rate-regulated subsidiaries and investments include:
| Rate-Regulated Subsidiary or Equity Investment | Accounting Policies Approved/Examined By | |
| Subsidiary | ||
| Tampa Electric Company (“TEC”) | Florida Public Service Commission (“FPSC”) and the Federal Energy Regulatory Commission (“FERC”) | |
| Nova Scotia Power Inc. (“NSPI”) | Nova Scotia Energy Board (“NSEB”), formerly Nova Scotia Utility and Review Board | |
| 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 |
6 | |||
| Significant Items Affecting Earnings |
6 | |||
| Consolidated Financial Highlights |
7 | |||
| Consolidated Income Statement Highlights |
8 | |||
| Business Overview and Outlook |
10 | |||
| Florida Electric Utility |
10 | |||
| Canadian Electric Utilities |
11 | |||
| Gas Utilities and Infrastructure |
12 | |||
| Other Electric Utilities |
12 | |||
| Other |
13 | |||
| Consolidated Balance Sheet Highlights |
14 | |||
| Other Developments |
15 | |||
| Financial Highlights |
16 | |||
| Florida Electric Utility |
16 | |||
| Canadian Electric Utilities |
17 |
| Gas Utilities and Infrastructure |
18 | |||
| Other Electric Utilities |
19 | |||
| Other |
20 | |||
| Liquidity and Capital Resources |
22 | |||
| Consolidated Cash Flow Highlights |
22 | |||
| Contractual Obligations |
24 | |||
| Debt Management |
25 | |||
| Credit Ratings |
26 | |||
| Guarantees and Letters of Credit |
26 | |||
| Outstanding Stock Data |
27 | |||
| Transactions with Related Parties |
28 | |||
| Risk Management including Financial Instruments |
28 | |||
| Disclosure and Internal Controls |
29 | |||
| Critical Accounting Estimates |
30 | |||
| Changes in Accounting Policies and Practices |
30 | |||
| Future Accounting Pronouncements |
30 | |||
| Summary of Quarterly Results |
32 |
FORWARD-LOOKING INFORMATION
This MD&A contains “forward-looking information” (“FLI”) and statements which reflect the current view with respect to the Company’s expectations regarding future growth, results of operations, performance, the expected timing and outcome of the pending sale of NMGC, the scope of the cybersecurity incident (the “Cybersecurity Incident”) and its expected impact on the Company’s financial position and results of operations, IT systems restoration, insurance recoveries, and business continuity processes as well as other matters relating to the Cybersecurity Incident, including business prospects and opportunities, and may not be appropriate for other purposes within the meaning of applicable Canadian securities laws. All such information and statements are made pursuant to safe harbour provisions contained in applicable securities legislation. The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecast”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “targets”, “will”, “would” and similar expressions are often intended to identify FLI, although not all FLI contains these identifying words. The FLI reflects management’s current beliefs and is based on information currently available to Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the time at which, such events, performance or results will be achieved.
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FLI is based on reasonable assumptions and is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the FLI. Factors that could cause results or events to differ from current expectations include, without limitation: regulatory and political risk; change in law risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; liquidity and capital markets risk; changes in credit ratings; future dividend growth, rate base growth, and adjusted earnings per common share (“EPS”) growth; timing and costs associated with certain capital investments; expected impacts on Emera of challenges in the global economy; potential impacts of trade disputes and tariffs; estimated energy consumption rates; maintenance of adequate insurance coverage and receipt of proceeds; changes in customer energy usage patterns; developments in technology that could impact demand for electricity; climate change risk; weather risk, including higher frequency and severity of weather events; risk of wildfires; unanticipated maintenance and other expenditures; system operating and maintenance risk; derivative financial instruments and hedging; interest rate risk; inflation risk; counterparty risk; disruption of fuel supply; country risks; supply chain risk; environmental risks; foreign exchange (“FX”); regulatory and government decisions, including changes to environmental legislation, financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of service area; risks and costs associated with failure of information technology (“IT”) infrastructure and cybersecurity incidents including IT systems restoration and business continuity processes; uncertainties associated with infectious diseases, pandemics and similar public health threats; market energy sales prices; labour relations; and availability of labour and management resources.
Readers are cautioned not to place undue reliance on FLI, as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the FLI. All FLI in this MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, Emera undertakes no obligation to revise or update any FLI as a result of new information, future events or otherwise.
INTRODUCTION AND STRATEGIC OVERVIEW
Emera (TSX/NYSE: EMA) is a North American provider of energy services, owning and operating a portfolio of cost-of-service, rate-regulated electric and gas utilities. Its largest operations are in Florida, with additional operations in Atlantic Canada, New Mexico, and the Caribbean. Emera is headquartered in Halifax, Nova Scotia, Canada.
Emera’s business strategy is centred on continued investment in its regulated utilities, combined with a focus on operational excellence and efficiency, to safely and reliably deliver energy to its 2.7 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 2024, Emera’s regulated cost-of-service utilities in Florida accounted for 65 per cent of average consolidated rate base, with Atlantic Canada comprising 27 per cent, and the Caribbean and New Mexico at 4 per cent each.
Emera’s capital investment plan is forecasted to be approximately $20 billion from 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 |
$ | 3,780 | $ | 3,730 | $ | 4,140 | $ | 4,180 | $ | 4,330 | $ | 20,160 | ||||||||||||
| Average consolidated rate base |
$ | 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 exclude NMGC. Refer to “Other Developments” for more information on the pending sale of NMGC.
Emera’s capital investment plan will be funded primarily through internally generated cash flows, debt raised at the operating company level consistent with regulated capital structures, equity issuances, and proceeds from the anticipated sale of NMGC. Generally, Emera’s equity requirements are expected to be funded through the issuance of hybrid equity, and the issuance of common equity through Emera’s dividend reinvestment plan (“DRIP”) and its at-the-market program (“ATM program”). Maintaining investment-grade credit ratings is a core strategic priority of the Company.
Emera has increased dividends per common share paid for 19 consecutive years and has provided forward annual dividend growth guidance of one to two per cent. Emera anticipates adjusted EPS average growth of five to seven per cent through 2027 which will support reduction in the ratio of dividend payout to adjusted net income. For further information on the non-GAAP ratios “Adjusted EPS” and “Dividend Payout Ratio of Adjusted Net Income”, refer to the “Non-GAAP Financial Measures and Ratios” section.
NON-GAAP FINANCIAL MEASURES AND RATIOS
Emera uses financial measures and ratios that do not have standardized meaning under USGAAP and are calculated by adjusting certain GAAP measures for specific items. They may not be comparable to similar measures presented by other entities. These measures and ratios are discussed and reconciled below.
Adjusted Net Income, Adjusted EPS – Basic and Dividend Payout Ratio of Adjusted Net Income
Emera calculates an adjusted net income attributable to common shareholders (“adjusted net income”) measure by excluding the items below from net income attributable to common shareholders. Management believes excluding these items better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the business.
Emera calculates adjusted net income for the Gas Utilities and Infrastructure, Other Electric Utilities, and Other segments. Reconciliation to the nearest GAAP measure is included in each segment. Refer to the “Financial Highlights – Gas Utilities and Infrastructure, Other Electric Utilities, and Other sections.
Adjusted EPS – basic and dividend payout ratio of adjusted net income are non-GAAP ratios which are calculated using adjusted net income, as described above. For further details on dividend payout ratio of adjusted net income, see the “Dividend Payout Ratio” section in the Company’s 2024 annual MD&A.
4
Mark-to-market (“MTM”) Adjustments:
Management believes excluding from net income the effect of MTM valuations and changes thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows, and therefore excludes MTM adjustments for evaluation of performance and incentive compensation. The MTM adjustments are related to the following:
| • | held-for-trading (“HFT”) commodity derivative instruments, including adjustments related to the price differential between the point where natural gas is sourced and where it is delivered, and the related amortization of transportation capacity recognized as a result of certain Emera Energy marketing and trading transactions; |
| • | the business activities of Bear Swamp Power Company LLC (“Bear Swamp”) included in Emera’s equity income; |
| • | equity securities held in BLPC and Emera Energy; and |
| • | FX hedges entered into to hedge USD denominated operating unit earnings exposure. |
Charges Related to the Pending Sale of NMGC:
On August 5, 2024, Emera entered into an agreement to sell NMGC. In Q2 2025, the Company recognized a $71 million non-cash impairment charge, after-tax, and an additional loss of $1 million in estimated transaction costs, after-tax, related to the pending sale. In Q3 2024, the Company recognized $206 million in non-cash goodwill and other impairment charges, after-tax, and an additional loss of $19 million in estimated transaction costs, after-tax, related to the pending sale. For further details, refer to the “Significant Items Affecting Earnings”, and “Other Developments” sections.
Gain on Sale of Emera’s Indirect Minority Interest in the Labrador Island Link (“Gain on sale of LIL”):
In Q2 2024, Emera recognized a $107 million gain, after tax and transaction costs, on the sale of LIL. For further details refer to the “Significant Items Affecting Earnings” section.
Reconciliation of Net Income Attributable to Common Shareholders to Adjusted Net Income
| For the | Three months ended September 30 |
Nine months ended September 30 |
||||||||||||||
| millions of dollars (except per share amounts) | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| Net income attributable to common shareholders |
$ | 228 | $ | 4 | $ | 946 | $ | 340 | ||||||||
| Less: |
- | (225) | (72) | (225) | ||||||||||||
| Gain on sale of LIL, after-tax (3) |
- | - | - | 107 | ||||||||||||
| MTM (loss) gain, after-tax (4) |
(35) | (7) | 140 | (145) | ||||||||||||
| Adjusted net income |
$ | 263 | $ | 236 | $ | 878 | $ | 603 | ||||||||
| EPS – basic |
$ | 0.76 | $ | 0.01 | $ | 3.17 | $ | 1.18 | ||||||||
| Adjusted EPS – basic |
$ | 0.88 | $ | 0.81 | $ | 2.94 | $ | 2.10 | ||||||||
| (1) Represents (i) a $71 million non-cash impairment charge, after-tax, and $1 million in transaction costs, after-tax for the nine months ended September 30, 2025 and (ii) $206 million in non-cash goodwill and other impairment charges, after-tax and $19 million in transaction costs, after-tax for the three and nine months ended September 30, 2024. |
| |||||||||||||||
| (2) Net of income tax recovery of nil for the three months ended September 30, 2025 (2024 - $20 million) and $5 million for the nine months ended September 30, 2025 (2024 - $20 million). |
| |||||||||||||||
| (3) Net of income tax expense of $75 million for the nine months ended September 30, 2024. |
| |||||||||||||||
| (4) Net of income tax recovery of $15 million for the three months ended September 30, 2025 (2024 – $4 million recovery) and $56 million income tax expense for the nine months ended September 30, 2025 (2024 – $60 million recovery). |
| |||||||||||||||
EBITDA and Adjusted EBITDA
Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) and adjusted EBITDA are non-GAAP financial measures used by Emera. These financial measures are used by numerous investors and lenders to better understand cash flows and credit quality. EBITDA is useful to assess Emera’s operating performance and indicates the Company’s ability to service or incur debt, invest in capital, and finance working capital requirements. Adjusted EBITDA represents EBITDA absent the income effect of MTM adjustments, charges related to the pending sale of NMGC, and the 2024 gain on the sale of LIL.
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Reconciliation of Net Income to EBITDA and Adjusted EBITDA:
| For the | Three months ended September 30 |
Nine months ended September 30 |
||||||||||||||
| millions of dollars | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| Net income (1) |
$ | 248 | $ | 23 | $ | 1,003 | $ | 395 | ||||||||
| Interest expense, net |
260 | 241 | 764 | 725 | ||||||||||||
| Income tax (recovery) expense |
6 | (9) | 116 | 40 | ||||||||||||
| Depreciation and amortization |
324 | 293 | 959 | 866 | ||||||||||||
| EBITDA |
$ | 838 | $ | 548 | $ | 2,842 | $ | 2,026 | ||||||||
| Less: |
- | (245) | (77) | (245) | ||||||||||||
| Gain on sale of LIL, excluding income tax |
- | - | - | 182 | ||||||||||||
| MTM (loss) gain, excluding income tax |
(50) | (11) | 196 | (205) | ||||||||||||
| Adjusted EBITDA |
$ | 888 | $ | 804 | $ | 2,723 | $ | 2,294 | ||||||||
| (1) Net income is before Non-controlling interest in subsidiaries and Preferred stock dividends. |
| |||||||||||||||
CONSOLIDATED FINANCIAL REVIEW
Significant Items Affecting Earnings
Charges Related to the Pending Sale of NMGC
2025:
In Q2 2025, Emera recognized a non-cash impairment charge of $75 million ($71 million after-tax, or $0.24 per common share) related to the remeasurement of the NMGC disposal group to fair value (“FV”) less costs to sell. This was recorded in “Impairment charges” on the Condensed Consolidated Statements of Income and included in the Other segment.
2024:
In Q3 2024, Emera recognized non-cash goodwill and other impairment charges of $221 million ($206 million after-tax, or $0.72 per common share) related to the NMGC reporting unit. These charges were recorded in “Impairment charges” on the Condensed Consolidated Statements of Income and included in the Other and Gas Utilities and Infrastructure segments. Additionally, in Q3 2024, Emera recorded a loss of $24 million ($19 million after-tax, or $0.06 per common share) in estimated transaction costs related to the pending sale. These transaction costs were included in “Other income, net” on the Condensed Consolidated Statements of Income and included in the Other segment.
For further details on the pending sale of NMGC, refer to the “Other Developments” section. For further details on the non-cash impairment and goodwill charges, refer to note 3 in the condensed consolidated interim financial statements.
Earnings Impact of MTM (Loss) Gain, After-Tax
MTM loss, after-tax, increased $28 million to $35 million in Q3 2025, compared to $7 million in Q3 2024, primarily due to a loss on Corporate FX hedges compared to a gain in prior year. Year-to-date, the 2024 MTM loss, after-tax, of $145 million, decreased $285 million to a $140 million MTM gain, after-tax, for the same period in 2025, primarily due to favourable changes in existing positions and lower amortization of gas transportation assets at Emera Energy Services (“EES”).
2024 Gain on Sale of LIL
On June 4, 2024, Emera completed the sale of its LIL equity interest. A gain on sale of $182 million after transaction costs ($107 million, after tax and transaction costs, or $0.37 per common share), was recognized in “Other Income, net” on the Condensed Consolidated Statements of Income and included in the Other segment. For further details, refer to note 3 in the condensed consolidated interim financial statements.
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Consolidated Financial Highlights
| For the millions of dollars |
Three months ended September 30 |
Nine months ended September 30 |
||||||||||||||
| Adjusted Net Income | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| Florida Electric Utility |
$ | 302 | $ | 252 | $ | 726 | $ | 524 | ||||||||
| Canadian Electric Utilities |
13 | 26 | 151 | 155 | ||||||||||||
| Gas Utilities and Infrastructure |
32 | 38 | 200 | 180 | ||||||||||||
| Other Electric Utilities |
16 | 10 | 28 | 27 | ||||||||||||
| Other |
(100) | (90) | (227) | (283) | ||||||||||||
| Adjusted net income |
$ | 263 | $ | 236 | $ | 878 | $ | 603 | ||||||||
| Charges related to the pending sale of NMGC, after-tax |
- | (225) | (72) | (225) | ||||||||||||
| Gain on sale of LIL, after-tax |
- | - | - | 107 | ||||||||||||
| MTM (loss) gain, after-tax |
(35) | (7) | 140 | (145) | ||||||||||||
| Net income attributable to common shareholders |
$ | 228 | $ | 4 | $ | 946 | $ | 340 | ||||||||
The following table highlights significant quarter-over-quarter and year-over-year changes in adjusted net income from 2024 to 2025:
| For the | Three months ended | Nine months ended | ||||||
| millions of dollars | September 30 | September 30 | ||||||
| Adjusted net income – 2024 |
$ | 236 | $ | 603 | ||||
| Operating Unit Performance |
||||||||
| Increased earnings at TEC due to higher revenue from new base rates and customer growth, partially offset by increased operating, maintenance and general expenses (“OM&G”), depreciation expense, interest and income tax expense. Year-over-year the increase was also due to the impact of favourable weather and the impact of a weaker CAD | 50 | 202 | ||||||
| Decreased income from equity investments due to the sale of LIL in Q2 2024 | - | (28) | ||||||
| Increased earnings at EES year-over-year due to favourable weather and resulting market conditions in Q1 2025 (higher natural gas prices and increased volatility) | (1) | 33 | ||||||
| Increased earnings year-over-year at NMGC due to higher revenue from new base rates and the impact of a weaker CAD | (4) | 22 | ||||||
| Decreased earnings quarter-over-quarter at NSPI due to increased OM&G and higher depreciation expense. Increased earnings year-over-year due to investment tax credits (“ITCs”) related to clean technology investments and increased sales volumes driven by favourable weather, partially offset by higher OM&G and higher depreciation expense | (11) | 30 | ||||||
| Corporate | ||||||||
| Increased income tax recovery due to decreased deferred income tax asset valuation allowance and increased loss before provision for income taxes | 11 | 18 | ||||||
| Increased interest expense primarily due to increased total debt, partially offset by lower interest rates | (3) | (10) | ||||||
| Increased OM&G quarter-over-quarter and decreased year-over-year primarily due to timing of the recognition on long term compensation expense and related hedges | (16) | 8 | ||||||
| Other Variances |
1 | - | ||||||
| Adjusted net income – 2025 |
$ | 263 | $ | 878 | ||||
For further details of contributions by reportable segments, refer to the “Financial Highlights” section.
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| For the | Nine months ended September 30 | |||||||
| millions of dollars | 2025 | 2024 | ||||||
| Operating cash flow before changes in working capital |
$ | 1,972 | $ | 1,732 | ||||
| Changes in working capital |
(382) | 220 | ||||||
| Operating cash flow |
$ | 1,590 | $ | 1,952 | ||||
| Investing cash flow |
$ | (2,518) | $ | (1,289) | ||||
| Financing cash flow |
$ | 941 | $ | (997) | ||||
For further discussion of cash flow, refer to the “Consolidated Cash Flow Highlights” section.
| As at |
September 30 | December 31 | ||||||
| millions of dollars |
2025 | 2024 | ||||||
| Total assets |
$ | 43,803 | $ | 42,951 | ||||
| Total long-term debt (including current portion) (1) |
$ | 18,979 | $ | 18,407 | ||||
| (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. |
| |||||||
Consolidated Income Statement Highlights
| For the | Three months ended | Nine months ended | ||||||||||||||||||||||
| millions of dollars | September 30 | September 30 | ||||||||||||||||||||||
| (except per share amounts) | 2025 | 2024 | Variance | 2025 | 2024 | Variance | ||||||||||||||||||
| Operating revenues |
$ | 2,106 | $ | 1,802 | $ | 304 | $ | 6,770 | $ | 5,437 | $ | 1,333 | ||||||||||||
| Operating expenses |
1,626 | 1,586 | (40) | 5,070 | 4,596 | (474) | ||||||||||||||||||
| Income from operations |
$ | 480 | $ | 216 | $ | 264 | $ | 1,700 | $ | 841 | $ | 859 | ||||||||||||
| Other income, net |
$ | 19 | $ | 14 | $ | 5 | $ | 135 | $ | 232 | $ | (97) | ||||||||||||
| Income tax expense (recovery) |
$ | 6 | $ | (9) | $ | (15) | $ | 116 | $ | 40 | $ | (76) | ||||||||||||
| Net income attributable to common shareholders |
$ | 228 | $ | 4 | $ | 224 | $ | 946 | $ | 340 | $ | 606 | ||||||||||||
| Adjusted net income |
$ | 263 | $ | 236 | $ | 27 | $ | 878 | $ | 603 | $ | 275 | ||||||||||||
| Weighted average shares of common stock outstanding (in millions) |
299.9 | 290.0 | 9.9 | 298.5 | 287.5 | 11.0 | ||||||||||||||||||
| EPS – basic |
$ | 0.76 | $ | 0.01 | $ | 0.75 | $ | 3.17 | $ | 1.18 | $ | 1.99 | ||||||||||||
| EPS – diluted |
$ | 0.76 | $ | 0.01 | $ | 0.75 | $ | 3.16 | $ | 1.18 | $ | 1.98 | ||||||||||||
| Adjusted EPS – basic |
$ | 0.88 | $ | 0.81 | $ | 0.07 | $ | 2.94 | $ | 2.10 | $ | 0.84 | ||||||||||||
| Dividends per common share declared |
$ | 0.7250 | $ | 0.7175 | $ | 0.0075 | $ | 2.1750 | $ | 2.1525 | $ | 0.0225 | ||||||||||||
| Adjusted EBITDA |
$ | 888 | $ | 804 | $ | 84 | $ | 2,723 | $ | 2,294 | $ | 429 | ||||||||||||
Operating Revenues
For Q3 2025, operating revenues increased $304 million compared to Q3 2024 and, excluding the change in MTM impacts, increased $316 million. The increase was due to higher storm cost recoveries at TEC and NSPI (offset in OM&G); new base rates at TEC and NMGC; higher regulatory deferral revenue at TEC; and the impact of a weaker CAD.
Year-to-date 2025, operating revenues increased $1,333 million compared to 2024 and, excluding the change in MTM impacts, increased $983 million. The increase was due to higher storm cost recoveries at TEC and NSPI (offset in OM&G); new base rates at TEC and NMGC; the impact of a weaker CAD; higher regulatory deferral revenue at TEC; increased marketing and trading margin at EES; favourable weather at NSPI and TEC; higher off-system sales at PGS; and customer growth at TEC.
8
Operating Expenses
For Q3 2025, operating expenses increased $40 million compared to Q3 2024. Excluding charges related to the pending sale of NMGC of $221 million recognized in 2024, operating expenses increased $261 million. Year-to-date operating expenses increased $474 million compared to 2024 and, excluding the change in charges related to the pending sale of NMGC of $146 million, increased $620 million. These increases were due to higher storm cost recognition at TEC and NSPI (offset in revenue); higher natural gas prices at TEC and PGS; increased depreciation at TEC, PGS and NMGC; and higher OM&G at NSPI, PGS and NMGC. The year-over-year increase was also due to the impact of a weaker CAD and higher regulated fuel for generation and purchase power and depreciation at NSPI.
Other Income, net
For Q3 2025, other income, net increased $5 million compared to Q3 2024 due to the 2024 transaction costs related to the pending sale of NMGC, partially offset by lower FX gains at Corporate in 2025.
Year-to-date, other income, net decreased $97 million compared to 2024 due to the gain on sale of LIL in 2024, partially offset by higher FX gains at Corporate in 2025, the 2024 transaction costs related to the pending sale of NMGC; and higher interest income at TEC.
Income Tax Expense (Recovery)
For Q3 2025, income tax expense increased $15 million compared to Q3 2024 due to the tax impact of lower charges related to the pending sale of NMGC, partially offset by decreased deferred income tax asset valuation allowance.
Year-to-date 2025, income tax expense increased $76 million compared to 2024 due to increased income before provision for income taxes (excluding the gain on sale of LIL in 2024 and charges related to the pending sale of NMGC) and the tax impact of lower charges related to the pending sale of NMGC. These were partially offset by the tax impact of the gain on sale of LIL in 2024; increased ITCs related to clean technology investments at NSPI; increased tax credits at TEC; and decreased deferred income tax asset valuation allowance.
Net Income and Adjusted Net Income
For Q3 2025, net income attributable to common shareholders, compared to Q3 2024, was favourably impacted by $225 million charges related to the pending sale of NMGC recognized in 2024 and unfavourably impacted by the $28 million increase in MTM losses. Excluding these impacts, adjusted net income increased $27 million, primarily due to increased earnings at TEC, partially offset by lower earnings at NSPI and NMGC and higher Corporate costs.
Year-to-date 2025, net income attributable to common shareholders, compared to the same period in 2024, was favourably impacted by the $285 million increase in MTM gain and the $153 million change in charges related to the pending sale of NMGC and unfavourably impacted by the $107 million gain on sale of LIL recognized in 2024. Excluding these changes, adjusted net income increased $275 million. The increase was primarily due to increased earnings at TEC, EES, NSPI and NMGC, and decreased Corporate costs. These were partially offset by lower equity earnings from LIL.
EPS – Basic and Adjusted EPS – Basic
For Q3 2025 and year-to-date, EPS – basic and adjusted EPS were higher due to increased earnings as discussed above, partially offset by the impact of an increase in weighted average shares outstanding.
Effect of Foreign Currency Translation
Results of foreign operations are translated at the weighted average rate of exchange, and assets and liabilities of foreign operations are translated at period end rates. For additional details on the effects of foreign currency translation, refer to the Company’s 2024 annual MD&A.
9
The relevant CAD/USD exchange rates for 2025 and 2024 are as follows:
| Three months ended September 30 |
Nine months ended September 30 |
Year ended December 31 |
||||||||||||||||||
| For the | 2025 | 2024 | 2025 | 2024 | 2024 | |||||||||||||||
| Weighted average CAD/USD |
$ | 1.38 | $ | 1.36 | $ | 1.41 | $ | 1.36 | $ | 1.36 | ||||||||||
| Period end CAD/USD exchange rate |
$ | 1.39 | $ | 1.35 | $ | 1.39 | $ | 1.35 | $ | 1.44 | ||||||||||
The table below includes Emera’s significant segments whose contributions to adjusted net income are recorded in USD currency:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of USD | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| Florida Electric Utility |
$ | 220 | $ | 186 | $ | 522 | $ | 385 | ||||||||
| Gas Utilities and Infrastructure (1)(2) |
19 | 25 | 129 | 122 | ||||||||||||
| Other Electric Utilities |
11 | 8 | 20 | 20 | ||||||||||||
| Other segment (3) |
(47 | ) | (58 | ) | (97 | ) | (108 | ) | ||||||||
| Total (2)(4) |
$ | 203 | $ | 161 | $ | 574 | $ | 419 | ||||||||
| (1) Includes USD adjusted net income from PGS, NMGC, SeaCoast and M&NP. |
| |||||||||||||||
| (2) Excludes $6 million USD after-tax in other impairment charges associated with the pending sale of NMGC for the three and nine months ended September 30, 2024. |
| |||||||||||||||
| (3) Includes Emera Energy’s USD adjusted net income from EES, Bear Swamp and interest expense on Emera Inc.’s USD denominated debt. |
| |||||||||||||||
| (4) Excludes $20 million USD MTM loss, after-tax, for the three months ended September 30, 2025 (2024 – $183 million USD MTM loss, after-tax) and $78 million USD MTM gain, after-tax, for the nine months ended September 30, 2025 (2024 – $272 million USD MTM loss, after-tax). |
| |||||||||||||||
The translation impact of a weaker CAD on USD earnings increased adjusted net income by $1 million in Q3 2025 and $16 million year-to-date, compared to the same periods in 2024. In Q3 2025, the impact of a weaker CAD on US denominated earnings was more than offset by the realized and unrealized losses on FX hedges used to mitigate the translation risk of USD earnings, resulting in a $10 million decrease to net income attributable to common shareholders compared to the same period in 2024. Year-to-date 2025, the impact of a weaker CAD on US denominated earnings, increased net income attributable to common shareholders by $52 million, compared to the same period in 2024. Impacts of the changes in the translation of the CAD include the impacts of Corporate FX hedges used to mitigate translation risk of USD earnings in the Other segment.
BUSINESS OVERVIEW AND OUTLOOK
There have been no material changes in Emera’s business overview and outlook from the Company’s 2024 annual MD&A, except for the updates disclosed below. The extent of the future impact of trade disputes and tariffs on the Company’s financial results and business operations continues to evolve, cannot be predicted at this time and will depend on future developments. To date, there has been no material financial impact on the Company. For information on risks associated with trade disputes and the imposition of tariffs, refer to the “Enterprise Risk and Risk Management” section in Emera’s 2024 annual MD&A.
Florida Electric Utility
TEC anticipates earning within the upper half of its ROE range in 2025. As a result of new base rates effective January 1, 2025, TEC’s 2025 USD earnings are expected to be higher than in 2024. TEC expects customer growth rates in 2025 to be comparable to 2024, reflective of the expected economic growth in Florida.
10
On September 4, 2025, TEC petitioned the FPSC to increase base revenue by $88 million USD to reflect the 2026 adjustment in accordance with its 2024 rate case decision. On November 4, 2025, the FPSC approved the adjustment, with new rates becoming effective January 1, 2026.
On February 3, 2025, the FPSC issued the final order approving the rate case decision, effective January 1, 2025. For additional details on the rate case decision, refer to note 7 in Emera’s 2024 annual audited consolidated financial statements. In February 2025, a motion for reconsideration on certain aspects of the final order was filed by an intervening party with the FPSC. On May 6, 2025, the FPSC denied the motion for reconsideration, except with respect to immaterial calculation corrections, and the final order was issued on June 11, 2025. In March 2025, two intervening parties each filed a notice of appeal to the Florida Supreme Court regarding the outcome of TEC’s 2024 base rate proceeding. To date, the intervening parties have not filed their briefs related to the appeal.
On February 4, 2025, the FPSC approved TEC’s petition for the recovery of $466 million USD of costs associated with Hurricane Idalia, Hurricane Debby, Hurricane Helene and Hurricane Milton, and the associated interest to replenish the storm reserve over an 18-month recovery period, which began in March 2025. The amount of cost-recovery is subject to a true-up mechanism with the FPSC. For additional details on the storm reserve, refer to note 7 in Emera’s annual audited consolidated financial statements.
In 2025, capital investment in the Florida Electric Utility segment is expected to be $1.7 billion USD (2024 – $1.4 billion USD), including allowance for funds used during construction (“AFUDC”). Capital projects include solar investments, storm hardening investments, grid modernization, and building resilience.
Canadian Electric Utilities
NSPI
NSPI anticipates earning below its allowed ROE range in 2025. NSPI expects earnings in 2025 to be lower than 2024, primarily due to higher operating costs related to the Cybersecurity Incident. Sales volumes are expected to be higher in 2025 than 2024.
On September 18, 2025, NSPI filed a consensus General Rate Application (“GRA”) with the NSEB, reflecting a settlement agreement reached with customer representatives. The settlement reflects more than six months of discussion, consultation, and information sharing. The GRA proposes average annual rate increases of 1.8 per cent in 2026 and 2.4 per cent in 2027. The proposed rates would result in annual revenue (fuel and non-fuel) increases of $62 million in 2026 and $108 million in 2027. The hearing for the matter is scheduled for January 2026 and a decision by the NSEB is expected in Q1 2026.
On March 5, 2025, NSPI, the Canada Infrastructure Bank (“CIB”) and the Wskijinu’k Mtmo’taqnuow Agency (“WMA”) announced the Wasoqonatl transmission line project to create a reliability intertie between Nova Scotia and New Brunswick. The project will be owned by a new regulated utility, WTI, which is wholly-owned by a newly formed limited partnership between NSPI, CIB and WMA. NSPI will be responsible for providing construction, operation, maintenance and administrative services to WTI. NSPI has a 50 per cent indirect voting interest in WTI which will be recorded as “Investments subject to significant influence” on Emera’s Consolidated Balance Sheets. As of September 30, 2025, NSPI’s investment is nominal.
In 2025, capital investment, including AFUDC, is expected to be $700 million (2024 – $487 million). NSPI is primarily investing in capital projects required to support power system reliability and reliable service for customers.
11
NSPML
Equity earnings from NSPML in 2025 are expected to be consistent with 2024. The NSPML investment is recorded as “Investments subject to significant influence” on Emera’s Consolidated Balance Sheets.
On July 18, 2025, NSPML submitted an application to the NSEB requesting recovery of approximately $199 million in Maritime Link costs for 2026. A decision is expected in Q4 2025.
On November 29, 2024, NSPML received approval from the NSEB to collect up to $197 million in 2025 from NSPI. Payments from NSPI are subject to a holdback of up to $4 million per month. There was no holdback recorded year-to-date in 2025. NSPML expects to file an application to terminate the holdback mechanism by early 2026.
NSPML does not anticipate any significant capital investment in 2025.
Gas Utilities and Infrastructure
PGS
PGS anticipates earning at the bottom of its allowed ROE range in 2025. USD earnings for 2025 are expected to be consistent with 2024.
On March 31, 2025, PGS filed a rate case with the FPSC for new rates to become effective January 1, 2026. On August 13, 2025, PGS and the intervening parties filed a settlement agreement with the FPSC for a $67 million USD increase in 2026 annual base rates, which includes $7 million USD from the cast iron and bare steel replacement rider, and additional adjustments of $25 million USD in 2027 and up to $5 million USD in 2028 (subject to FPSC approval). This reflects a 10.30 per cent midpoint ROE and 54.7 per cent equity thickness. On October 31, 2025, the FPSC issued the final order approving the settlement, effective January 1, 2026.
In 2025, capital investment, including AFUDC, is expected to be approximately $330 million USD (2024 – $323 million USD). PGS is investing to maintain the reliability of its system and support customer growth.
NMGC
On August 5, 2024, Emera announced an agreement to sell NMGC. As a result of the pending sale, NMGC’s assets and liabilities were classified as held for sale beginning in Q3 2024. In July 2025, the procedural schedule for the NMPRC regulatory process was revised with the public hearing rescheduled from June 2025 to November 2025. The transaction is expected to close in early 2026. For more information on the pending transaction, refer to the “Other Developments” section.
As a result of the change in expected timing of the pending sale, NMGC’s USD earnings contribution in 2025 are expected to be slightly higher than the adjusted USD earnings in 2024 due to higher revenue from new base rates.
Other Electric Utilities
Other Electric Utilities’ USD earnings in 2025 are expected to be consistent with the prior year.
In 2025, capital investment in the Other Electric Utilities segment is expected to be approximately $70 million USD, including AFUDC (2024 – $59 million USD), primarily in projects to support system reliability.
12
GBPC
On June 1, 2024, the Electricity Act, 2024 took effect. The legislation purports to remove the jurisdiction of the GBPA over GBPC and to have the Utilities Regulation and Competition Authority (“URCA”), another Bahamian regulator, regulate GBPC. URCA filed a claim in the Supreme Court of the Bahamas, seeking an order that the GBPA be prohibited and restrained from considering and/or approving any adjustment to rates sought by GBPC. URCA contends that it has regulatory authority over electricity provision on Grand Bahama pursuant to the Electricity Act. Management does not expect that the outcome of the proceedings will have a material impact to Emera.
Other
The adjusted net loss from the Other segment is expected to be lower in 2025 than 2024, due to higher contributions from EES and the wind down of Block Energy LLC in Q4 2024.
Earnings from EES are generally dependent on market conditions. In particular, volatility in natural gas and electricity markets, which can be influenced by weather, local supply constraints and other supply and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1 and Q4 usually providing the greatest opportunity for earnings. EES is generally expected to deliver annual adjusted net income of $15 to $30 million USD. In light of a strong performance in Q1, EES expects adjusted net income between $35 and $45 million USD in 2025.
The Other segment does not anticipate any significant capital investment in 2025.
13
CONSOLIDATED BALANCE SHEET HIGHLIGHTS
Significant changes in the Consolidated Balance Sheets between December 31, 2024 and September 30, 2025 include:
| millions of dollars | Total Increase (Decrease) |
Explanation of Increase (Decrease) | ||||
| Assets | ||||||
| Inventory |
$ | 69 | Increased due to higher natural gas prices and volumes at EES, and higher volumes of materials inventory at NSPI | |||
| Derivative instruments (current and long-term) | 103 | Increased due to reversal of 2024 contracts at EES, and changes in FX hedges at Corporate | ||||
| Regulatory assets (current and long-term) |
(195) | Decreased due to lower storm cost recovery assets at TEC and NSPI and the effect of FX translation of Emera’s non-Canadian affiliates. These were partially offset by higher deferrals related to the fuel adjustment mechanism (“FAM”) and deferred income tax regulatory asset at NSPI | ||||
| Receivables and other assets (current and long-term) | 395 | Increased due to higher operating revenue at TEC and timing of accounts receivable at NSPI. These were partially offset by decreased cash collateral positions on derivative instruments at EES and NSPI | ||||
| Assets held for sale (current and long-term), net of liabilities (1) | (109) | Decreased primarily due to non-cash impairment charge recognized in 2025, lower accounts receivable due to seasonal trends of the business, and the effect of FX translation at NMGC | ||||
| PP&E, net of accumulated depreciation and amortization | 832 | Increased due to capital additions in excess of depreciation, partially offset by the effect of FX translation of Emera’s non-Canadian affiliates | ||||
| Goodwill |
(191) | Decreased due to the effect of FX translation of Emera’s non-Canadian affiliates | ||||
| Liabilities and Equity | ||||||
| Short-term debt and long-term debt (including current portion) | $ | 837 | Increased due to issuance of long-term debt at TEC, and proceeds from issuance of a non-revolving term credit facility at NSPI. These were partially offset by the effect of FX translation of Emera’s non-Canadian affiliates and repayment of committed credit facilities at TEC and PGS | |||
| Accounts payable | (179) | Decreased due to lower storm cost payments at TEC, lower commodity prices at EES and the effect of FX translation of Emera’s non-Canadian affiliates. These were partially offset by timing of accounts payable at NSPI | ||||
| Deferred income tax liabilities, net of deferred income tax assets | 108 | Increased due to tax deductions in excess of accounting depreciation related to PP&E. This was partially offset by increased tax credits at TEC and the effect of FX translation of Emera’s non-Canadian affiliates | ||||
| Derivative instruments (current and long-term) | (70) | Decreased due to reversal of 2024 contracts and changes in existing positions at EES and changes in FX hedges at Corporate. These were partially offset by new contracts at EES | ||||
| Regulatory liabilities (current and long-term) |
(179) | Decreased due to lower FAM liability at NSPI, cost recovery clause liabilities and decreased deferred income tax regulatory liability at TEC, and the effect of FX translation of Emera’s non-Canadian affiliates | ||||
| Other liabilities (current and long-term) |
168 | Increased due to timing of interest payments at Corporate, timing of property tax payments at TEC, and accrued output-based pricing system (“OBPS”) carbon tax and increased customer deposits at NSPI | ||||
| Common stock |
270 | Increased due to shares issued | ||||
| Accumulated other comprehensive income |
(376) | Decreased due to the effect of FX translation of Emera’s non-Canadian affiliates | ||||
| Retained earnings |
298 | 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.
14
OTHER DEVELOPMENTS
Increase in Common Dividend
On September 25, 2025, the Emera Board of Directors approved an increase in the annual common share dividend rate to $2.93 from $2.90 per common share. The first payment will be effective November 14, 2025.
Cybersecurity Incident
On April 25, 2025, Emera and NSPI discovered a Cybersecurity Incident involving unauthorized access into certain parts of its Canadian network and servers supporting portions of its business applications. Immediately following detection of the external threat, incident response and business continuity protocols were activated, including the engagement of leading third-party cybersecurity experts. Actions were taken to contain and isolate the affected servers and prevent further intrusion and to notify law enforcement in Canada and the United States (“US”). There was no disruption to any of the Company’s Canadian physical operations, including at NSPI’s generation, transmission and distribution facilities, the Maritime Link, or the Brunswick Pipeline. There was no impact to Emera’s US or Caribbean utilities’ operations. The post-incident investigation is nearing completion.
The Company implemented business continuity processes for certain impacted business and administrative functions at its Canadian affiliates. The systematic restoration of affected IT systems and corresponding transition away from business continuity processes is progressing and will continue in a planned, controlled and phased approach. For more information on the impact on internal controls over financial reporting, refer to the “Disclosure and Internal Controls” section. The Company maintains cyber insurance coverage and is working with its insurer on the claims process. At this time, the Cybersecurity Incident is not expected to have a material impact on the Company’s financial position or results of operations. For information on risks associated with cybersecurity incidents generally, refer to the “Enterprise Risk and Risk Management” section of Emera’s annual 2024 MD&A.
Pending Sale of NMGC
On August 5, 2024, Emera entered into an agreement to sell its indirect wholly-owned subsidiary NMGC for a total enterprise value of approximately $1.3 billion USD, consisting of cash proceeds and the transfer of debt and customary closing adjustments. As a result of the pending sale, NMGC’s assets and liabilities were classified as held for sale in Q3 2024 and the carrying value of the assets and liabilities were adjusted to FV less cost to sell. In July 2025, the procedural schedule for the NMPRC regulatory process was revised with the public hearing rescheduled from June 2025 to November 2025. The transaction is expected to close in early 2026.
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 (“carrying amount”). On June 30, 2025, the Company remeasured the NMGC disposal group at the lower of its carrying amount and FV less costs to sell. As a result of the change in the expected timing of the transaction close, a non-cash impairment charge of $75 million ($71 million, after-tax), or $55 million USD ($52 million USD, after-tax), was recorded in “Impairment charges” on the Condensed Consolidated Statements of Income in Q2 2025. An additional loss for estimated future transaction costs of $2 million ($1 million after-tax) was recorded in “Other income, net” on the Condensed Consolidated Statements of Income in Q2 2025. There were no additional adjustments recorded in Q3 2025 as a result of the FV less cost to sell assessment performed as at September 30, 2025.
15
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 $79 million ($57 million USD) was recorded on these assets from August 5, 2024, the date they were classified as held for sale, through September 30, 2025. Of the $79 million ($57 million USD) recorded to date, $53 million ($38 million USD) was recorded in 2025.
US One Big Beautiful Bill Act (“OBBBA”)
On July 4, 2025, the OBBBA was signed into law. The OBBBA makes permanent many of the expired and expiring tax provisions originally enacted in the Tax Cuts and Jobs Act of 2017. It also includes significant changes in future years to the timing and availability of several clean energy tax credits previously enacted in the Inflation Reduction Act, including the investment tax credit and production tax credit. On August 15, 2025, the Internal Revenue Service released guidance on determining when wind and solar projects have begun construction for purposes of qualifying for these tax credits. Emera is currently evaluating the impact of the enacted changes but does not anticipate a material impact on the Company.
New York Stock Exchange (“NYSE”) Listing
Emera filed a registration statement dated May 1, 2025 on Form 40-F with the US Securities and Exchange Commission (“SEC”) to register its common shares under Section 12 of the Securities Exchange Act of 1934. Emera subsequently completed the listing of its common shares on the NYSE and commenced trading on May 28, 2025. Emera’s common shares continue to be listed and traded on the Toronto Stock Exchange.
Appointments
Executive
Effective December 1, 2025, Jared Green will become Emera’s new Chief Financial Officer, succeeding Greg Blunden. Mr. Green most recently served as President and Chief Executive Officer of TriSummit Utilities (previously AltaGas Canada).
Board of Directors
Effective September 17, 2025, Isabelle Courville joined the Emera Board of Directors. Ms. Courville is Chair of the Board of Canadian Pacific Kansas City and previously served as President of Hydro-Québec Distribution and Hydro Québec TransÉnergie, as well as President of Bell Canada’s Enterprise Group.
FINANCIAL HIGHLIGHTS
Florida Electric Utility
| For the | Three months ended September 30 |
Nine months ended September 30 |
||||||||||||||
| millions of USD (except as indicated) | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| Operating revenues – regulated electric |
$ | 921 | $ | 724 | $ | 2,409 | $ | 1,944 | ||||||||
| Regulated fuel for generation and purchased power |
$ | 204 | $ | 164 | $ | 553 | $ | 471 | ||||||||
| Contribution to consolidated net income |
$ | 220 | $ | 186 | $ | 522 | $ | 385 | ||||||||
| Contribution to consolidated net income – CAD |
$ | 302 | $ | 252 | $ | 726 | $ | 524 | ||||||||
| Electric sales volumes (Gigawatt hours (“GWh”)) |
6,270 | 6,437 | 16,306 | 16,080 | ||||||||||||
| Electric production volumes (GWh) |
6,589 | 6,661 | 17,150 | 17,017 | ||||||||||||
| Average fuel cost in dollars per megawatt hour (“MWh”) |
$ | 31 | $ | 25 | $ | 32 | $ | 28 | ||||||||
16
The impact of the change in FX rates increased CAD earnings for the three and nine months ended September 30, 2025, by $3 million and $16 million, respectively.
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | Nine months ended | ||||||
| millions of USD | September 30 | September 30 | ||||||
| Contribution to consolidated net income – 2024 |
$ | 186 | $ | 385 | ||||
| Increased operating revenues primarily due to new base rates, storm cost recovery revenue (offset in OM&G), higher regulatory deferral revenue and customer growth. Year-over-year the increase was also due to the impact of favourable weather ($20 million) | 197 | 465 | ||||||
| Increased fuel for generation and purchased power due to higher natural gas prices and higher purchased power | (40) | (82) | ||||||
| Increased OM&G due to higher storm cost recognition (offset in revenue), and higher costs for employee benefits; operations related to solar investments; and software maintenance. These were partially offset by the timing of recognition of regulatory deferrals | (86) | (158) | ||||||
| Increased depreciation and amortization due to facilities and capital projects placed in service | (13) | (34) | ||||||
| Increased interest expense due to higher borrowings | (8) | (16) | ||||||
| Increased income tax expense primarily due to higher income before provision for income taxes, partially offset by increased amortization of deferred ITCs. Year-over-year the increase was also partially offset by higher benefit from production tax credits | (10) | (34) | ||||||
| Other | (6) | (4) | ||||||
| Contribution to consolidated net income – 2025 |
$ | 220 | $ | 522 | ||||
Canadian Electric Utilities
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars (except as indicated) | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| Operating revenues – regulated electric |
$ | 405 | $ | 399 | $ | 1,440 | $ | 1,376 | ||||||||
| Regulated fuel for generation and purchased power (1) |
$ | 222 | $ | 243 | $ | 796 | $ | 725 | ||||||||
| Contribution to consolidated net income |
$ | 13 | $ | 26 | $ | 151 | $ | 155 | ||||||||
| Electric sales volumes (GWh) |
2,230 | 2,285 | 7,936 | 7,849 | ||||||||||||
| Electric production volumes (GWh) |
2,380 | 2,428 | 8,466 | 8,361 | ||||||||||||
| Average fuel costs in dollars per MWh |
$ | 93 | $ | 100 | $ | 94 | $ | 87 | ||||||||
(1) Regulated fuel for generation and purchased power includes NSPI’s FAM on the Condensed Consolidated Statements of Income, however, it is excluded in the segment overview.
Canadian Electric Utilities’ contribution to consolidated net income is summarized in the following table:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| NSPI |
$ | 3 | $ | 14 | $ | 119 | $ | 89 | ||||||||
| Equity investment in NSPML |
10 | 12 | 32 | 38 | ||||||||||||
| Equity investment in LIL (1) |
- | - | - | 28 | ||||||||||||
| Contribution to consolidated net income |
$ | 13 | $ | 26 | $ | 151 | $ | 155 | ||||||||
(1) On June 4, 2024, Emera completed the sale of LIL. For further details, refer to note 3 in the condensed consolidated interim financial statements.
17
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | Nine months ended | ||||||
| millions of dollars | September 30 | September 30 | ||||||
| Contribution to consolidated net income – 2024 |
$ | 26 | $ | 155 | ||||
| Increased operating revenue at NSPI due to higher fuel and storm cost recoveries, partially offset by lower industrial sales volumes. Year-over-year increase also due to favourable weather and increased residential and commercial sales volumes | 6 | 64 | ||||||
| Decreased regulated fuel for generation and purchased power quarter-over-quarter due to lower commodity prices, partially offset by higher Maritime Link assessment costs. Year-over year increased due to changes in generation mix, increased Maritime Link assessment costs, higher sales volumes, and higher Nova Scotia OBPS carbon tax, partially offset by lower commodity prices | 21 | (71) | ||||||
| Decreased FAM quarter-over-quarter due to lower under-recovery of fuel costs. Year-over-year increased due to higher under-recovery of fuel costs | (25) | 39 | ||||||
| Increased OM&G at NSPI due to higher costs for transmission and distribution operations, and power generation operations, partially offset by higher administrative overhead allocated to property, plant and equipment (“PP&E”). Year-over-year increase was also due to costs related to the Cybersecurity Incident, partially offset by lower storm restoration costs | (11) | (28) | ||||||
| Increased depreciation and amortization due to increased PP&E in service | (3) | (12) | ||||||
| Decreased income from equity investments due to the sale of LIL | - | (28) | ||||||
| Increased income tax recovery year-over-year primarily due to clean technology ITCs in 2025 | 1 | 39 | ||||||
| Other | (2) | (7) | ||||||
| Contribution to consolidated net income – 2025 |
$ | 13 | $ | 151 | ||||
Gas Utilities and Infrastructure
On August 5, 2024, Emera announced an agreement to sell NMGC. As a result of the pending sale, NMGC’s assets and liabilities were classified as held for sale beginning in Q3 2024. In July 2025, the procedural schedule for the NMPRC regulatory process was revised with the public hearing rescheduled from June 2025 to November 2025. The transaction is expected to close in early 2026. For more information on the pending transaction, refer to the “Other Developments” section.
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of USD (except as indicated) | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| Operating revenues – regulated gas (1) |
$ | 227 | $ | 216 | $ | 908 | $ | 843 | ||||||||
| Operating revenues – non-regulated |
5 | 5 | 13 | 12 | ||||||||||||
| Total operating revenue |
$ | 232 | $ | 221 | $ | 921 | $ | 855 | ||||||||
| Regulated cost of natural gas |
$ | 39 | $ | 34 | $ | 245 | $ | 208 | ||||||||
| Contribution to consolidated adjusted net income |
$ | 23 | $ | 28 | $ | 141 | $ | 133 | ||||||||
| Contribution to consolidated adjusted net income – CAD |
$ | 32 | $ | 38 | $ | 200 | $ | 180 | ||||||||
| Charges related to the pending sale of NMGC, after-tax (2) |
- | (6 | ) | - | (6 | ) | ||||||||||
| Contribution to consolidated net income |
$ | 23 | $ | 22 | $ | 141 | $ | 127 | ||||||||
| Contribution to consolidated net income – CAD |
$ | 32 | $ | 30 | $ | 200 | $ | 172 | ||||||||
| Gas sales volumes (millions of Therms) |
743 | 729 | 2,359 | 2,370 | ||||||||||||
| (1) Operating revenues – regulated gas includes $11 million of finance income from Brunswick Pipeline (2024 – $11 million) for the three months ended September 30, 2025 and $34 million (2024 – $34 million) for the nine months ended September 30, 2025. |
| |||||||||||||||
| (2) Includes an other impairment charge, net of an income tax recovery of $2 million for the three and nine months ended September 30, 2024. |
| |||||||||||||||
18
Gas Utilities and Infrastructure’s contribution to consolidated adjusted net income is summarized in the following table:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of USD | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| PGS |
$ | 21 | $ | 24 | $ | 86 | $ | 92 | ||||||||
| NMGC |
(6) | (3) | 30 | 16 | ||||||||||||
| Other |
8 | 7 | 25 | 25 | ||||||||||||
| Contribution to consolidated adjusted net income |
$ | 23 | $ | 28 | $ | 141 | $ | 133 | ||||||||
The impact of the change in FX rates was minimal for the three months ended September 30, 2025, and increased CAD earnings for the nine months ended September 30, 2025 by $8 million.
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | Nine months ended | ||||||
| millions of USD | September 30 | September 30 | ||||||
| Contribution to consolidated net income – 2024 |
$ | 22 | $ | 127 | ||||
| Increased gas revenues due to higher fuel revenue and off-system sales at PGS and new base rates at NMGC | 11 | 66 | ||||||
| Increased cost of natural gas due to higher natural gas prices at PGS and NMGC | (5) | (37) | ||||||
| Increased OM&G primarily due to higher labour costs at PGS and NMGC, partially offset by the timing of deferred clause recoveries at PGS | (6) | (4) | ||||||
| Increased depreciation primarily due to capital projects placed in service at PGS and NMGC | (4) | (10) | ||||||
| Other | 5 | (1) | ||||||
| Contribution to consolidated net income – 2025 | $ | 23 | $ | 141 | ||||
Other Electric Utilities
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of USD (except as indicated) | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| Operating revenues – regulated electric |
$ | 115 | $ | 110 | $ | 311 | $ | 306 | ||||||||
| Regulated fuel for generation and purchased power |
$ | 60 | $ | 58 | $ | 160 | $ | 160 | ||||||||
| Contribution to consolidated adjusted net income |
$ | 11 | $ | 8 | $ | 20 | $ | 20 | ||||||||
| Contribution to consolidated adjusted net income – CAD |
$ | 16 | $ | 10 | $ | 28 | $ | 27 | ||||||||
| Equity securities MTM gain |
$ | - | $ | - | $ | 1 | $ | 1 | ||||||||
| Contribution to consolidated net income |
$ | 11 | $ | 8 | $ | 21 | $ | 21 | ||||||||
| Contribution to consolidated net income – CAD |
$ | 16 | $ | 11 | $ | 30 | $ | 29 | ||||||||
| Electric sales volumes (GWh) |
349 | 346 | 977 | 984 | ||||||||||||
| Electric production volumes (GWh) |
377 | 371 | 1,045 | 1,056 | ||||||||||||
| Average fuel costs in dollars per MWh |
$ | 159 | $ | 156 | $ | 153 | $ | 152 | ||||||||
Other Electric Utilities’ contribution to consolidated adjusted net income is summarized in the following table:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of USD | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| BLPC |
$ | 6 | $ | 4 | $ | 12 | $ | 14 | ||||||||
| GBPC |
6 | 4 | 9 | 8 | ||||||||||||
| Other |
(1) | - | (1) | (2) | ||||||||||||
| Contribution to consolidated adjusted net income |
$ | 11 | $ | 8 | $ | 20 | $ | 20 | ||||||||
19
The impact of the change in FX rates on CAD earnings and adjusted net income for the three and nine months ended September 30, 2025 was minimal.
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | Nine months ended | ||||||
| millions of USD | September 30 | September 30 | ||||||
| Contribution to consolidated net income – 2024 |
$ | 8 | $ | 21 | ||||
| Increased operating revenues – regulated electric due to higher fuel revenue at GBPC and higher miscellaneous revenue at BLPC | 5 | 5 | ||||||
| Increased regulated fuel for generation and purchased power due to higher fuel costs at GBPC | (2) | - | ||||||
| Increased income tax expense due to the remeasurement of deferred income tax liabilities as a result of a corporate income tax rate change at BLPC | - | (2) | ||||||
| Other | - | (3) | ||||||
| Contribution to consolidated net income – 2025 |
$ | 11 | $ | 21 | ||||
Other
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| Marketing and trading margin (1)(2) |
$ | (3) | $ | (7) | $ | 98 | $ | 42 | ||||||||
| Other non-regulated operating revenue |
9 | 7 | 25 | 22 | ||||||||||||
| Total operating revenues – non-regulated |
$ | 6 | $ | - | $ | 123 | $ | 64 | ||||||||
| Contribution to consolidated adjusted net (loss) income |
$ | (100) | $ | (90) | $ | (227) | $ | (283) | ||||||||
| Charges related to the pending sale of NMGC, after-tax (3) |
- | (217) | (72) | (217) | ||||||||||||
| Gain on sale of LIL, after-tax (4)(5) |
- | - | - | 107 | ||||||||||||
| MTM (loss) gain, after-tax (6) |
(35) | (8) | 138 | (147) | ||||||||||||
| Contribution to consolidated net (loss) income |
$ | (135) | $ | (315) | $ | (161) | $ | (540) | ||||||||
(1) Marketing and trading margin represents EES’s purchases and sales of natural gas and electricity, pipeline and storage capacity costs and energy asset management services’ revenues.
(2) Marketing and trading margin excludes a pre-tax MTM loss of $37 million for the three months ended September 30, 2025 (2024 – $37 million loss) and a gain of $160 million for the nine months ended September 30, 2025 (2024 – $198 million loss).
(3) Includes an impairment charge of $75 million ($71 million after-tax) and transaction costs of $2 million ($1 million after-tax) for the nine months ended September 30, 2025, and impairment charges of $210 million ($198 million after-tax) and transaction costs of $24 million ($19 million after-tax) for the three and nine months ended September 30, 2024.
(4) On June 4, 2024, Emera completed the sale of its LIL equity interest. For further details on the transaction, refer to note 3 in the condensed consolidated interim financial statements.
(5) Net of income tax expense of $75 million for the nine months ended September 30, 2024.
(6) Net of income tax recovery of $15 million for the three months ended September 30, 2025 (2024 – $4 million recovery) and $56 million income tax expense for the nine months ended September 30, 2025 (2024 – $60 million recovery).
Other’s contribution to consolidated adjusted net (loss) income is summarized in the following table:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| Emera Energy |
||||||||||||||||
| EES |
$ | (8) | $ | (7) | $ | 47 | $ | 14 | ||||||||
| Other |
(1) | 2 | (5) | 4 | ||||||||||||
| Corporate – see breakdown of contribution below |
(96) | (82) | (274) | (287) | ||||||||||||
| Block Energy LLC |
5 | (3) | 6 | (13) | ||||||||||||
| Other |
- | - | (1) | (1) | ||||||||||||
| Contribution to consolidated adjusted net (loss) income |
$ | (100) | $ | (90) | $ | (227) | $ | (283) | ||||||||
20
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | Nine months ended | ||||||
| millions of dollars | September 30 | September 30 | ||||||
| Contribution to consolidated net (loss) income – 2024 |
$ | (315) | $ | (540) | ||||
| Increased marketing and trading margin due to favourable weather conditions that led to higher natural gas prices and increased volatility that created profitable opportunities | 4 | 56 | ||||||
| Increased OM&G quarter-over-quarter primarily due to a lower gain on the long-term incentive hedge. Decreased year-over-year due to a higher gain on the long-term incentive hedge, partially offset by higher long-term compensation expense and increased consulting costs | (18 | ) | 6 | |||||
| Decreased equity earnings at Bear Swamp due to lower generation as a result of an outage | (4 | ) | (14 | ) | ||||
| Increased interest expense primarily due to increased total debt, partially offset by decreased interest rates | (3 | ) | (10 | ) | ||||
| Increased income tax recovery quarter-over-quarter due to decreased deferred income tax asset valuation allowance and increased loss before provision for income taxes. Increased income tax recovery year-over-year due to decreased deferred income tax asset valuation allowance and a favourable tax impact of foreign currency translation, partially offset by decreased loss before provision for income taxes | 9 | 5 | ||||||
| Charges related to the pending sale of NMGC, after-tax | 217 | 145 | ||||||
| Gain on sale of LIL, after-tax | - | (107 | ) | |||||
| Increased MTM loss, after-tax, quarter-over-quarter due primarily to a loss on Corporate FX hedges compared to a gain in prior year. Decreased MTM loss, after-tax, year-over-year primarily due to favourable changes in existing positions and lower amortization of gas transportation assets at EES | (27 | ) | 285 | |||||
| Other | 2 | 13 | ||||||
| Contribution to consolidated net (loss) income – 2025 |
$ | (135 | ) | $ | (161 | ) | ||
Corporate
Corporate’s adjusted loss is summarized in the following table:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| Operating expenses (1) |
$ | (16) | $ | - | $ | (43) | $ | (51) | ||||||||
| Interest expense |
(93) | (90) | (280) | (270) | ||||||||||||
| Income tax recovery |
38 | 27 | 112 | 94 | ||||||||||||
| Preferred dividends |
(19) | (18) | (56) | (54) | ||||||||||||
| Other (2)(3) |
(6) | (1) | (7) | (6) | ||||||||||||
| Corporate adjusted net loss (4)(5)(6) |
$ | (96) | $ | (82) | $ | (274) | $ | (287) | ||||||||
(1) Operating expenses include OM&G and depreciation.
(2) Other includes realized gains and losses on FX hedges entered into to hedge USD denominated operating unit earnings exposure.
(3) Includes a realized net loss, pre-tax of $2 million ($2 million after-tax) for the three months ended September 30, 2025 (2024 – $3 million net loss, pre-tax and $2 million loss, after-tax) and a $12 million net loss, pre-tax ($9 million after-tax) for the nine months ended September 30, 2025 (2024 – $7 million net loss, pre-tax and $5 million loss, after-tax) on FX hedges, as discussed above.
(4) Excludes a MTM loss, after-tax, of $10 million for the three months ended September 30, 2025 (2024 – $6 million gain, after-tax) and a MTM gain, after-tax of $23 million for the nine months ended September 30, 2025 (2024 – $6 million loss, after-tax).
(5) Excludes a gain on sale of LIL, after-tax and transaction costs, of $107 million for the nine months ended September 30, 2024.
(6) Excludes certain charges related to the pending sale of NMGC of $77 million ($72 million after-tax) for the nine months ended September 30, 2025, and $234 million ($217 million after-tax) for the three and nine months ended September 30, 2024.
21
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 and supports ongoing growth. Capital investments at Emera’s regulated utilities are subject to regulatory approval.
Emera has sufficient liquidity to service debt obligations as they come due to meet any near-term capital investment requirements as currently planned. Emera plans to use cash from operations, debt raised at the utilities, Corporate equity, and proceeds from the pending sale of NMGC to support normal operations, repayment of existing debt, and capital requirements. Debt raised at certain of the Company’s utilities is subject to applicable regulatory approvals. Generally, Corporate equity requirements in support of the Company’s capital investment plan are expected to be funded through issuance of hybrid equity and issuance of common equity through Emera’s DRIP and ATM programs.
Emera has total committed credit facilities with varying maturities that cumulatively provide $2.8 billion CAD and $1.6 billion USD of credit, with approximately $640 million CAD and $834 million USD undrawn and available at September 30, 2025. The Company was holding a cash balance of $215 million, which includes $3 million classified as assets held for sale, related to the pending sale of NMGC, at September 30, 2025. For further discussion, refer to the “Debt Management” section below.
Consolidated Cash Flow Highlights
Significant changes in the Condensed Consolidated Statements of Cash Flows between the nine months ended September 30, 2025 and 2024 include:
| millions of dollars | 2025 | 2024 | Change | |||||||||
| Cash, cash equivalents, restricted cash, and cash associated with assets held for sale, beginning of period | $ | 221 | $ | 588 | $ | (367) | ||||||
| Provided by (used in): |
||||||||||||
| Operating cash flow before changes in working capital |
1,972 | 1,732 | 240 | |||||||||
| Changes in non-cash working capital |
(382) | 220 | (602) | |||||||||
| Operating activities |
$ | 1,590 | $ | 1,952 | $ | (362) | ||||||
| Investing activities |
(2,518) | (1,289) | (1,229) | |||||||||
| Financing activities |
941 | (997) | 1,938 | |||||||||
| Effect of exchange rate changes on cash, cash equivalents, restricted cash, and cash associated with assets held for sale | (5) | 10 | (15) | |||||||||
| Cash, cash equivalents, restricted cash and cash associated with assets held for sale, end of period | $ | 229 | $ | 264 | $ | (35 | ) | |||||
22
Cash Flow from Operating Activities
Net cash provided by operating activities decreased $362 million to $1,590 million for the nine months ended September 30, 2025, compared to $1,952 million for the same period in 2024.
Cash from operations before changes in working capital increased $240 million year-over-year. This increase was due to new base rates at TEC and NMGC, higher storm cost recoveries at TEC, higher marketing and trading margin at EES, and higher fuel over-recoveries at PGS. These were partially offset by proceeds from the FAM asset sale at NSPI in Q2 2024 and higher fuel under-recoveries at TEC.
Changes in non-cash working capital decreased operating cash flow by $602 million year-over-year. This decrease was due to unfavourable changes in accounts payable at TEC due to the timing and payment of storm invoices, unfavourable changes in accounts receivable at TEC due to increased base rates and storm cost recoveries, unfavourable changes in accounts receivable and inventory at NSPI and the recognition of ITCs related to clean technology investments at NSPI. These were partially offset by timing of accounts receivable at PGS and timing of accounts payable at PGS and NSPI.
Cash Flow from Investing Activities
Net cash used in investing activities increased $1,229 million to $2,518 million for the nine months ended September 30, 2025, compared to $1,289 million for the same period in 2024. The increase was due to the proceeds of $927 million received in 2024 on the sale of LIL and higher capital investment, partially offset by proceeds on the disposal of assets.
Capital investments, including AFUDC, for the nine months ended September 30, 2025, were $2,615 million, compared to $2,259 million for the same period in 2024. Details of the 2025 capital investment by segment are shown below:
| • | $1,616 million – Florida Electric Utility (2024 – $1,375 million); |
| • | $491 million – Canadian Electric Utilities (2024 – $389 million); |
| • | $444 million – Gas Utilities and Infrastructure (2024 – $437 million); |
| • | $63 million – Other Electric Utilities (2024 – $54 million); and |
| • | $1 million – Other (2024 – $4 million). |
Cash Flow from Financing Activities
Net cash provided by financing activities increased $1,938 million to $941 million for the nine months ended September 30, 2025, compared to cash used in financing activities of $997 million for the same period in 2024. This increase was due to lower net repayments under committed credit facilities at Emera and TEC, proceeds from short-term debt at NSPI, higher net borrowings on committed credit facilities at NSPI and NMGC, retirement of long-term debt at Emera US Finance LP, TEC and NMGC in 2024 and higher proceeds from long-term debt at TEC. These were partially offset by the 2024 issuance of long-term debt at EUSHI Finance Inc. (“EUSHI Finance”), higher repayments of short-term debt at TECO Finance Inc, lower issuance of common stock, and retirement of long-term debt at NSPI.
23
Contractual Obligations
As at September 30, 2025, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:
| millions of dollars | 2025 | 2026 | 2027 | 2028 | 2029 | Thereafter | Total | |||||||||||||||||||||
| Long-term debt principal (1)(2) |
$ | 17 | $ | 1,282 | $ | 89 | $ | 834 | $ | 2,190 | $ | 15,374 | $ | 19,786 | ||||||||||||||
| Interest payment obligations (3)(4) |
344 | 937 | 907 | 902 | 811 | 14,002 | 17,903 | |||||||||||||||||||||
| Purchased power (5) |
89 | 316 | 406 | 396 | 445 | 5,951 | 7,603 | |||||||||||||||||||||
| Transportation (6)(7) |
241 | 725 | 578 | 466 | 407 | 3,122 | 5,539 | |||||||||||||||||||||
| Fuel, gas supply and storage (8) |
227 | 660 | 130 | 45 | 40 | 99 | 1,201 | |||||||||||||||||||||
| Capital projects |
342 | 149 | 40 | 5 | 2 | - | 538 | |||||||||||||||||||||
| Pension and post-retirement obligations (9) |
8 | 32 | 67 | 71 | 71 | 219 | 468 | |||||||||||||||||||||
| Asset retirement obligations |
10 | 3 | 3 | 5 | 3 | 432 | 456 | |||||||||||||||||||||
| Other |
42 | 72 | 58 | 50 | 48 | 264 | 534 | |||||||||||||||||||||
| $ | 1,320 | $ | 4,176 | $ | 2,278 | $ | 2,774 | $ | 4,017 | $ | 39,463 | $ | 54,028 | |||||||||||||||
As detailed below, contractual obligations at September 30, 2025 includes those related to NMGC. On completion of the sale of NMGC, all remaining future contractual obligations will be transferred to the buyer. For further details on the pending transaction, refer to the “Other Developments” section.
(1) Includes $673 million related to NMGC (2026: $97 million and $576 million thereafter).
(2) The Company’s $1.2 billion USD and $500 million USD hybrid notes mature in 2076 and 2054, respectively, and these maturity dates have been used in the computation of the Company’s long-term debt principal and interest payment obligations at September 30, 2025.The Company has the option to repay such notes in advance of maturity upon exercise of the Company’s redemption
rights in accordance with the terms of the applicable indenture. Emera’s $1.2 billion USD hybrid notes are redeemable,
at Emera’s option, in June 2026.
(3) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at September 30, 2025, including any expected required payment under associated swap agreements.
(4) Includes $324 million related to NMGC (2025: $7 million, 2026: $26 million, 2027: $22 million, 2028: $22 million, 2029: $22 million, and $225 million thereafter).
(5) Annual requirement to purchase electricity from Independent Power Producers or other utilities over varying contract lengths.
(6) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $124 million related to a gas transportation contract between PGS and SeaCoast through 2040.
(7) Includes $65 million related to NMGC (2025: $11 million, 2026: $23 million, 2027: $15 million, 2028: $12 million, and 2029: $4 million).
(8) Includes $186 million related to NMGC (2025: $53 million, 2026: $117 million, 2027: $13 million, and 2028: $3 million).
(9) Includes the estimated contractual obligation, which is calculated as the current legislatively required contributions to the registered funded pension plans, plus the estimated costs of further benefit accruals contracted under NSPI’s Collective Bargaining Agreement and estimated benefit payments related to other unfunded benefit plans.
NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. In November 2024, the NSEB approved the collection of up to $197 million from NSPI for the recovery of Maritime Link costs in 2025. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to NSEB approval.
Emera has committed to obtain certain transmission rights in New Brunswick during summer periods (April through October, inclusive) for Newfoundland and Labrador Hydro’s use, if requested, effective August 15, 2021 and continuing for 50 years. As transmission rights are contracted, the obligations are included within “Other” in the above table.
24
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 September 30, 2025.
| 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 | $ | 1,083 | $ | 217 | |||||||||
| NSPI – committed revolving credit facility |
June 2029 | 800 | 377 | 423 | ||||||||||||
| NSPI – non-revolving facility |
May 2026 | 500 | 500 | - | ||||||||||||
| Emera – non-revolving facility |
February 2026 | 200 | 200 | - | ||||||||||||
| In USD: |
||||||||||||||||
| TEC – committed revolving credit facility |
December 2028 | 800 | 511 | 289 | ||||||||||||
| TECO Finance, Inc. – committed revolving credit facility |
December 2028 | 400 | 23 | 377 | ||||||||||||
| PGS – revolving facility |
December 2028 | 250 | 144 | 106 | ||||||||||||
| NMGC – revolving credit facility |
December 2027 | 125 | 83 | 42 | ||||||||||||
| Other – committed revolving credit facilities |
Various | 28 | 8 | 20 | ||||||||||||
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 September 30, 2025.
Recent significant financing activity for Emera and its subsidiaries are discussed below by segment:
Florida Electric Utility
On March 6, 2025, TEC issued $600 million USD of senior unsecured notes that bear interest at 5.15 per cent with a maturity date of March 1, 2035. Proceeds from this issuance were used for the repayment of a portion of TEC’s outstanding commercial paper.
Canadian Electric Utilities
On May 21, 2025, NSPI entered into a $500 million non-revolving facility which matures on May 21, 2026. The credit agreement contains customary representations and warranties, events of default and financial and other covenants. The non-revolving facility’s interest rates are referenced to the Term CORRA or prime rate, plus a margin. Proceeds from this facility were used for general corporate purposes.
Gas Utilities and Infrastructure
On October 23, 2025, NMGC entered into a $70 million USD, 364-day term loan agreement which matures on October 22, 2026. The credit agreement contains customary representations and warranties, events of default and financial and other covenants. The non-revolving facility’s interest rates are referenced to the Term SOFR plus a margin. Proceeds from this facility were used for general corporate purposes.
On September 19, 2025, NMGC amended its $125 million USD unsecured committed revolving credit facility to extend the maturity date from December 17, 2026, to December 17, 2027. There were no other changes in commercial terms from the prior agreement.
25
Other
On September 25, 2025, EUSHI Finance, Emera US Holdings Inc. and Emera filed a shelf registration statement on Form F-10 and Form F-3 (“Registration Statement”), with the Nova Scotia Securities Commission (“NSSC”) and the SEC under the US/Canada Multijurisdictional Disclosure System. The Registration Statement was filed in connection with the prospective offer and issue by EUSHI Finance of one or more series of senior and/or subordinated unsecured debt securities (“Debt Securities”), in an aggregate principal amount of up to $3 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 October 3, 2025, EUSHI Finance completed an issuance of $750 million USD fixed-to-fixed reset rate junior subordinated notes, pursuant to the prospectus supplement dated September 29, 2025, to the Base Shelf Prospectus. The notes initially bear interest at a rate of 6.25 per cent, and will reset on April 1, 2031, and every five years thereafter, to a rate per annum equal to the five-year US treasury rate plus 2.509 per cent, subject to an interest rate floor of 6.25 per cent. The notes mature on April 1, 2056. EUSHI Finance, at its option, may redeem the notes, in whole or in part, 90 days prior to the first interest reset date, and any semi-annual interest payment date thereafter, at a redemption price equal to the principal amount, plus accrued and unpaid interest on the notes to be redeemed, in accordance with the terms of the prospectus supplement; and otherwise, at the times and the redemption prices described in the prospectus supplement. The notes are fully and unconditionally guaranteed, on a joint, several and subordinated basis, by Emera, and Emera US Holdings Inc. Proceeds from this issuance will be used for general corporate purposes, including repayment of existing debt.
On February 20, 2025, Emera amended its $200 million unsecured non-revolving facility to extend the maturity date from February 19, 2025 to February 19, 2026. There were no other material changes to the terms from the prior agreement.
Credit Ratings
Emera’s credit ratings are consistent with those disclosed in the Company’s 2024 annual MD&A, with material updates noted below:
On May 27, 2025, Fitch Ratings revised its outlook on Emera, TEC and PGS to stable from negative with no changes to existing ratings.
Guarantees and Letters of Credit
Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2024
annual MD&A, with material updates as noted below:
Emera, on behalf of Brunswick Pipeline, issued a standby letter of credit for $22 million to secure obligations under a non-revolving loan agreement. This standby letter of credit has a one-year term, expiring on March 31, 2026, and will be renewed annually, as required.
The Company has standby letters of credit and surety bonds in the amount of $136 million USD (December 31, 2024 – $105 million USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed annually, as required.
Emera, on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The expiry date of this letter of credit was extended to June 2026. The amount committed as at September 30, 2025 was $70 million (December 31, 2024 – $58 million).
26
Outstanding Stock Data
Common Stock
| millions of | millions of | |||||||
| Issued and outstanding: | shares | dollars | ||||||
| Balance, December 31, 2024 |
295.94 | $ | 9,042 | |||||
| Conversion of Convertible Debentures |
0.02 | 1 | ||||||
| Issuance of common stock under ATM program (1) |
0.19 | 10 | ||||||
| Issued under the DRIP, net of discounts |
3.80 | 225 | ||||||
| Senior management stock options exercised and Employee Share Purchase Plan |
0.65 | 34 | ||||||
| Balance, September 30, 2025 |
300.60 | $ | 9,312 | |||||
(1) For the three months ended September 30, 2025, no common shares were issued under Emera’s ATM program. For the nine months ended September 30, 2025, a total of 187,600 common shares were issued under Emera’s ATM program at an average price of $53.58 per share for gross proceeds of $10 million ($10 million, net of after-tax issuance costs). As at September 30, 2025, an aggregate gross sales limit of $326 million remained available for issuance under the ATM program, which expired on November 4, 2025.
As at November 5, 2025, the amount of issued and outstanding common shares was 300.7 million.
If all outstanding stock options were converted as at November 5, 2025, an additional 4.1 million common shares would be issued and outstanding.
Preferred Stock
As at November 5, 2025, 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 July 9, 2025, Emera announced that it would not redeem the currently outstanding Cumulative 5-Year Rate Reset Preferred Shares, Series A (“Series A Shares”) or the Cumulative Floating Rate First Preferred Shares, Series B (“Series B Shares”) on August 15, 2025 (the “Conversion Date”).
On July 16, 2025, Emera announced a dividend rate of 4.951 per cent per annum on the Series A Shares during the five-year period commencing on August 15, 2025 and ending on (and inclusive of) August 14, 2030 ($0.3094 per Series A Share per quarter).
During the conversion period between July 16, 2025 and July 31, 2025, the holders of Series A Shares had the right, at their option, to convert all or any of their Series A Shares, on a one-for-one basis, into Series B Shares and the holders of Series B Shares had the right, at their option, to convert all or any of their Series B Shares, on a one-for-one basis, into Series A Shares. On August 7, 2025, Emera announced, after having taken into account all shares tendered for conversion by holders of its Series A Shares and Series B Shares, as the case may be (collectively, the “Holders”), by the end of the conversion period, the Company has determined that there would be outstanding on the Conversion Date less than 1 million Series B Shares. Therefore, in accordance with certain rights, privileges, restrictions and conditions attaching to the Series A Shares and the Series B Shares, the Company advised the Holders that no Series A Shares would be converted into Series B Shares and all remaining Series B Shares would automatically be converted into Series A Shares on a one-for-one basis on the Conversion Date. On the Conversion Date, there were 6 million Series A Shares and no Series B Shares outstanding.
On January 16, 2025, Emera announced that the annual fixed dividend per share for Series F shares would be reset from $1.0505 to $1.4372 for the five-year period from and including February 15, 2025.
27
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 $49 million for the three months ended September 30, 2025 (2024 – $41 million) and $140 million for the nine months ended September 30, 2025 (2024 – $123 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 $1 million for the three months ended September 30, 2025 (2024 – $2 million) and $12 million for the nine months ended September 30, 2025 (2024 – $8 million). |
| • | On March 5, 2025, NSPI sold development assets associated with the Wasoqonatl transmission line project to WTI for consideration of $15 million. The development assets were sold at cost with no gain or loss recognized in the Condensed Consolidated Statements of Income. |
As at September 30, 2025, Emera and its associated companies had $41 million due to related parties (December 31, 2024 – $24 million) recorded in “Other Current Liabilities” on the Condensed Consolidated Balance Sheets.
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
There have been no material changes in Emera’s risk management profile and practices from those disclosed in the Company’s 2024 annual MD&A. In April 2025, Emera and NSPI were impacted by a Cybersecurity Incident, as more particularly described in the “Other Developments” section. For more information on risks associated with cybersecurity generally, refer to the “Enterprise Risk and Risk Management” section of Emera’s 2024 annual MD&A.
28
Derivative Assets and Liabilities Recognized on the Balance Sheet
| As at | September 30 | December 31 | ||||||
| millions of dollars | 2025 | 2024 | ||||||
| Regulatory Deferral: |
||||||||
| Derivative instrument assets (1) |
$ | 27 | $ | 45 | ||||
| Derivative instrument liabilities (2) |
(36) | (40) | ||||||
| Regulatory assets (1) |
36 | 53 | ||||||
| Regulatory liabilities (2) |
(22) | (44) | ||||||
| Net asset |
$ | 5 | $ | 14 | ||||
| HFT Derivatives: |
||||||||
| Derivative instrument assets (1) |
$ | 206 | $ | 122 | ||||
| Derivative instrument liabilities (2) |
(505) | (542) | ||||||
| Net liability |
$ | (299) | $ | (420) | ||||
| Other Derivatives: |
||||||||
| Derivative instrument assets (1) |
$ | 41 | $ | - | ||||
| Derivative instrument liabilities (2) |
(6) | (36) | ||||||
| Net asset (liability) |
$ | 35 | $ | (36) | ||||
(1) Current, other and held for sale assets.
(2) Current, long-term and held for sale liabilities.
Realized and Unrealized Gains (Losses) Recognized in Net Income
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| Regulatory Deferral: |
||||||||||||||||
| Regulated fuel for generation and purchased power (1) |
$ | (6) | $ | (15) | $ | (12) | $ | (36) | ||||||||
| HFT Derivatives: |
||||||||||||||||
| Non-regulated operating revenues |
$ | 16 | $ | 59 | $ | 480 | $ | 209 | ||||||||
| Other Derivatives: |
||||||||||||||||
| OM&G |
$ | 11 | $ | 22 | $ | 36 | $ | 8 | ||||||||
| Other income, net |
(16) | 5 | 21 | (15) | ||||||||||||
| Net gains (losses) |
$ | (5) | $ | 27 | $ | 57 | $ | (7) | ||||||||
| Total net gains |
$ | 5 | $ | 71 | $ | 525 | $ | 166 | ||||||||
(1) Realized gains (losses) on derivative instruments settled and consumed in the period, hedging relationships that have been terminated or the hedged transaction is no longer probable. Realized gains (losses) recorded in inventory will be recognized in “Regulated fuel for generation and purchased power” when the hedged item is consumed.
As of September 30, 2025, the unrealized gain in accumulated other comprehensive income was $10 million, after-tax (December 31, 2024 – $12 million, after-tax). For the three and nine months ended September 30, 2025, unrealized gains of $1 million (September 30, 2024 – $1 million) and $2 (September 30, 2024 – $2 million), respectively, have been reclassified into interest expense.
DISCLOSURE AND INTERNAL CONTROLS
Management is responsible for establishing and maintaining adequate disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings. The Company’s internal control framework is based on criteria published in the Internal Control - Integrated Framework (2013), a report issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer, designed the Company’s DC&P and ICFR as at September 30, 2025, to provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.
29
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 this 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 quarter ended September 30, 2025. For more information on the Cybersecurity Incident, refer to the “Other Developments” section.
There were no other changes in the Company’s ICFR during the quarter ended September 30, 2025, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
CRITICAL ACCOUNTING ESTIMATES
The preparation of unaudited condensed consolidated interim financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. In Q2 2025, the Company recognized a $75 million CAD ($55 million USD), pre-tax, non-cash impairment charge related to the pending sale of NMGC. For more information on the impairment charge, refer to note 3 in the condensed consolidated interim financial statements. There were no other material changes in the nature of the Company’s critical accounting estimates from those disclosed in Emera’s 2024 annual MD&A.
CHANGES IN ACCOUNTING POLICIES AND PRACTICES
Future Accounting Pronouncements
The Company considers the applicability and impact of all Accounting Standard Updates (“ASU”) issued by the Financial Accounting Standards Board (“FASB”). The following updates have been issued by the FASB, but as allowed, have not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be either not applicable to the Company or to have an insignificant impact on the consolidated financial statements.
30
Targeted Improvements to the Accounting for Internal-Use Software
In September 2025, the FASB issued ASU 2025-06, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Targeted Improvements to the Accounting for Internal-Use Software. The standard update modernizes accounting for internal-use software by eliminating references to project stages and clarifying the threshold to begin capitalizing costs. The standard update also specifies that the disclosure requirements under ASC 360, Property, Plant and Equipment, apply to capitalized software costs accounted under ASC 350-40. The guidance will be effective for annual reporting periods beginning after December 15, 2027, and interim reporting periods within those annual reporting periods. Early adoption is permitted. The standard updates are to be applied using either a prospective, retrospective, or modified transition approach. The Company is currently evaluating the impact of adoption of the standard update on its consolidated financial statements.
Disaggregation of Income Statement Expenses
In November 2024, the FASB issued ASU 2024-03, Income Statement Reporting – Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard update improves the disclosures about a public business entity’s expenses by requiring more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation and amortization) included within income statement expense captions. The guidance will be effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The standard updates are to be applied prospectively with the option for retrospective application. The Company is currently evaluating the impact of adoption of the standard update on its consolidated financial statements disclosures.
Improvements to Income Tax Disclosures
In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The standard enhances the transparency, decision usefulness and effectiveness of income tax disclosures by requiring consistent categories and greater disaggregation of information in the reconciliation of income taxes computed using the enacted statutory income tax rate to the actual income tax provision and effective income tax rate, as well as the disaggregation of income taxes paid (refunded) by jurisdiction. The standard also requires disclosure of income (loss) before provision for income taxes and income tax expense (recovery) in accordance with U.S. Securities and Exchange Commission Regulation S-X 210.4-08(h), Rules of General Application – General Notes to Financial Statements: Income Tax Expense, and the removal of disclosures no longer considered cost beneficial or relevant. The guidance will be effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted. The standard will be applied on a prospective basis, with retrospective application permitted. The Company is currently evaluating the impact of adoption of the standard on its consolidated financial statements disclosures.
31
SUMMARY OF QUARTERLY RESULTS
| For the quarter ended millions of dollars |
Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | ||||||||||||||||||||||||
| (except per share amounts) | 2025 | 2025 | 2025 | 2024 | 2024 | 2024 | 2024 | 2023 | ||||||||||||||||||||||||
| Operating revenues |
$ | 2,106 | $ | 1,988 | $ | 2,676 | $ | 1,763 | $ | 1,802 | $ | 1,617 | $ | 2,018 | $ | 1,972 | ||||||||||||||||
| Net income attributable to common shareholders | $ | 228 | $ | 135 | $ | 583 | $ | 154 | $ | 4 | $ | 129 | $ | 207 | $ | 289 | ||||||||||||||||
| EPS – basic |
$ | 0.76 | $ | 0.45 | $ | 1.96 | $ | 0.52 | $ | 0.01 | $ | 0.45 | $ | 0.73 | $ | 1.04 | ||||||||||||||||
| EPS – diluted |
$ | 0.76 | $ | 0.45 | $ | 1.96 | $ | 0.52 | $ | 0.01 | $ | 0.45 | $ | 0.73 | $ | 1.04 | ||||||||||||||||
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.
Q3 2025 compared to Q3 2024
For explanation of variances, refer to the “Consolidated Income Statement Highlights” section.
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.
Q1 2025 compared to Q1 2024
Q1 2025 net income attributable to common shareholders increased by $376 million and EPS – basic and diluted increased by $1.23 compared to Q1 2024. The increases were primarily due to decreased MTM losses; increased earnings at TEC, NSPI, EES and NMGC; the impact of a weaker CAD; and decreased Corporate OM&G. These changes were partially offset by decreased income from equity investments due to the sale of LIL. The change in EPS was also impacted by an increase in weighted average shares outstanding.
Q4 2024 compared to Q4 2023
Q4 2024 net income attributable to common shareholders decreased by $135 million and EPS – basic and diluted decreased by $0.52 compared to Q4 2023. The decreases were primarily due to decreased MTM gains; charges related to wind-down costs and certain asset impairments; lower equity earnings from LIL; increased Corporate OM&G due to the timing difference in the valuation of long-term incentive expenses and related hedges; decreased earnings at Emera Energy; and increased Corporate interest expense. These changes were partially offset by the tax benefit related to a specific financing structure and its wind-up; increased earnings at NSPI, Other Electric Utilities, NMGC, PGS, and TEC; valuation allowance reversal related to the gain on sale of LIL; and increased Corporate income tax recovery. The change in EPS was also impacted by an increase in weighted average shares outstanding.
32
Exhibit 99.2
EMERA INCORPORATED
Unaudited Condensed Consolidated
Interim Financial Statements
September 30, 2025 and 2024
1
Emera Incorporated
Condensed Consolidated Statements of Income (Unaudited)
| Three months ended | Nine months ended | |||||||||||||||
| For the |
September 30 | September 30 | ||||||||||||||
| millions of dollars (except per share amounts) |
2025 | 2024 | 2025 | 2024 | ||||||||||||
| Operating revenues |
||||||||||||||||
| Regulated electric |
$ | 1,829 | $ | 1,534 | $ | 5,227 | $ | 4,431 | ||||||||
| Regulated gas |
308 | 291 | 1,264 | 1,134 | ||||||||||||
| Non-regulated |
(31) | (23) | 279 | (128) | ||||||||||||
| Total operating revenues (note 5) |
2,106 | 1,802 | 6,770 | 5,437 | ||||||||||||
| Operating expenses |
||||||||||||||||
| Regulated fuel for generation and purchased power |
547 | 484 | 1,653 | 1,487 | ||||||||||||
| Regulated cost of natural gas |
53 | 46 | 346 | 282 | ||||||||||||
| Operating, maintenance and general expenses (“OM&G”) |
578 | 432 | 1,673 | 1,415 | ||||||||||||
| Provincial, state and municipal taxes |
124 | 110 | 364 | 325 | ||||||||||||
| Depreciation and amortization |
324 | 293 | 959 | 866 | ||||||||||||
| Impairment charges (note 3) |
- | 221 | 75 | 221 | ||||||||||||
| Total operating expenses |
1,626 | 1,586 | 5,070 | 4,596 | ||||||||||||
| Income from operations |
480 | 216 | 1,700 | 841 | ||||||||||||
| Income from equity investments (note 7) |
15 | 25 | 48 | 87 | ||||||||||||
| Other income, net (note 8) |
19 | 14 | 135 | 232 | ||||||||||||
| Interest expense, net |
260 | 241 | 764 | 725 | ||||||||||||
| Income before provision for income taxes |
254 | 14 | 1,119 | 435 | ||||||||||||
| Income tax expense (recovery) (note 9) |
6 | (9) | 116 | 40 | ||||||||||||
| Net income |
248 | 23 | 1,003 | 395 | ||||||||||||
| Non-controlling interest in subsidiaries (“NCI”) |
1 | 1 | 1 | 1 | ||||||||||||
| Preferred stock dividends |
19 | 18 | 56 | 54 | ||||||||||||
| Net income attributable to common shareholders |
$ | 228 | $ | 4 | $ | 946 | $ | 340 | ||||||||
| Weighted average shares of common stock outstanding (in millions) (note 11) |
||||||||||||||||
| Basic |
299.9 | 290.0 | 298.5 | 287.5 | ||||||||||||
| Diluted |
300.6 | 290.1 | 299.0 | 287.6 | ||||||||||||
| Earnings per common share (note 11) |
||||||||||||||||
| Basic |
$ | 0.76 | $ | 0.01 | $ | 3.17 | $ | 1.18 | ||||||||
| Diluted |
$ | 0.76 | $ | 0.01 | $ | 3.16 | $ | 1.18 | ||||||||
| Dividends per common share declared |
$ | 0.7250 | $ | 0.7175 | $ | 2.1750 | $ | 2.1525 | ||||||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
2
Emera Incorporated
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
| Three months ended | Nine months ended | |||||||||||||||
| For the |
September 30 | September 30 | ||||||||||||||
| millions of dollars |
2025 | 2024 | 2025 | 2024 | ||||||||||||
| Net income |
$ | 248 | $ | 23 | $ | 1,003 | $ | 395 | ||||||||
| Other comprehensive income (loss) (“OCI”), net of tax |
||||||||||||||||
| Foreign currency translation adjustment (1) |
257 | (165) | (428) | 240 | ||||||||||||
| Unrealized (losses) gains on net investment hedges (2) |
(33) | 22 | 56 | (33) | ||||||||||||
| Cash flow hedges – net of reclassification adjustment for gains included in income |
(1) | (1) | (2) | (2) | ||||||||||||
| Unrealized gains on available-for-sale investment |
1 | - | 1 | 1 | ||||||||||||
| Net change in unrecognized pension and post-retirement benefit obligation |
1 | - | (3) | 1 | ||||||||||||
| OCI (1) |
$ | 225 | $ | (144) | $ | (376) | $ | 207 | ||||||||
| Comprehensive income (loss) |
473 | (121) | 627 | 602 | ||||||||||||
| Comprehensive income attributable to NCI |
1 | 1 | 1 | 1 | ||||||||||||
| Comprehensive income (loss) of Emera Incorporated |
$ | 472 | $ | (122) | $ | 626 | $ | 601 | ||||||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
(1) Net of tax expense of $3 million (2024 – $2 million recovery) for the three months ended September 30, 2025 and tax recovery of $6 million (2024 – $3 million expense) for the nine months ended September 30, 2025.
(2) The Company has designated $1.2 billion United States dollar (“USD”) denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in USD denominated operations.
3
Emera Incorporated
Condensed Consolidated Balance Sheets (Unaudited)
| As at |
September 30 | December 31 | ||||||
| millions of dollars |
2025 | 2024 | ||||||
| Assets |
||||||||
| Current assets |
||||||||
| Cash and cash equivalents |
$ | 212 | $ | 196 | ||||
| Restricted cash |
14 | 17 | ||||||
| Inventory |
850 | 781 | ||||||
| Derivative instruments (notes 13 and 14) |
221 | 115 | ||||||
| Regulatory assets (note 6) |
500 | 595 | ||||||
| Receivables and other current assets (note 16) |
2,105 | 1,811 | ||||||
| Assets held for sale (note 3) |
124 | 173 | ||||||
| 4,026 | 3,688 | |||||||
| Property, plant and equipment (“PP&E”), net of accumulated depreciation and amortization of $10,793 and $10,442, respectively |
27,000 | 26,168 | ||||||
| Other assets |
||||||||
| Deferred income taxes (note 9) |
371 | 392 | ||||||
| Derivative instruments (notes 13 and 14) |
48 | 51 | ||||||
| Regulatory assets (note 6) |
2,732 | 2,832 | ||||||
| Net investment in direct finance and sales type leases |
583 | 610 | ||||||
| Investments subject to significant influence (note 7) |
637 | 654 | ||||||
| Goodwill |
5,667 | 5,858 | ||||||
| Other long-term assets (note 23) |
639 | 538 | ||||||
| Assets held for sale (note 3) |
2,100 | 2,160 | ||||||
| 12,777 | 13,095 | |||||||
| Total assets |
$ | 43,803 | $ | 42,951 |
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 |
September 30 | December 31 | ||||||
| millions of dollars |
2025 | 2024 | ||||||
| Liabilities and Equity |
||||||||
| Current liabilities |
||||||||
| Short-term debt (note 18) |
$ | 1,665 | $ | 1,400 | ||||
| Current portion of long-term debt (note 19) |
1,170 | 234 | ||||||
| Accounts payable |
1,813 | 1,992 | ||||||
| Derivative instruments (notes 13 and 14) |
473 | 526 | ||||||
| Regulatory liabilities (note 6) |
218 | 262 | ||||||
| Other current liabilities |
614 | 489 | ||||||
| Liabilities associated with assets held for sale (note 3) |
323 | 212 | ||||||
| 6,276 | 5,115 | |||||||
| Long-term liabilities |
||||||||
| Long-term debt (note 19) |
17,809 | 18,173 | ||||||
| Deferred income taxes (note 9) |
2,418 | 2,331 | ||||||
| Derivative instruments (notes 13 and 14) |
74 | 91 | ||||||
| Regulatory liabilities (note 6) |
1,483 | 1,618 | ||||||
| Pension and post-retirement liabilities (note 17) |
269 | 274 | ||||||
| Other long-term liabilities (note 7) |
953 | 910 | ||||||
| Liabilities associated with assets held for sale (note 3) |
1,037 | 1,148 | ||||||
| 24,043 | 24,545 | |||||||
| Equity |
||||||||
| Common stock (note 10) |
9,312 | 9,042 | ||||||
| Cumulative preferred stock |
1,422 | 1,422 | ||||||
| Contributed surplus |
85 | 84 | ||||||
| Accumulated other comprehensive income (“AOCI’) (note 12) |
885 | 1,261 | ||||||
| Retained earnings |
1,766 | 1,468 | ||||||
| Total Emera Incorporated equity |
13,470 | 13,277 | ||||||
| Non-controlling interest in subsidiaries (“NCI”) |
14 | 14 | ||||||
| Total equity |
13,484 | 13,291 | ||||||
| Total liabilities and equity |
$ | 43,803 | $ | 42,951 | ||||
| Commitments and contingencies (note 20) |
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 | Nine months ended September 30 | |||||||
| millions of dollars | 2025 | 2024 | ||||||
| Operating activities | ||||||||
| Net income | $ | 1,003 | $ | 395 | ||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
| Depreciation and amortization |
963 | 878 | ||||||
| Income from equity investments, net of dividends |
5 | (10) | ||||||
| Allowance for funds used during construction (“AFUDC”) – equity |
(49) | (36) | ||||||
| Deferred income taxes, net |
119 | 14 | ||||||
| Net change in pension and post-retirement liabilities |
(38) | (40) | ||||||
| Nova Scotia Power (“NSPI”) fuel adjustment mechanism (“FAM”) |
(123) | 18 | ||||||
| Net change in fair value (“FV”) of derivative instruments |
(185) | 50 | ||||||
| Net change in regulatory assets and liabilities |
225 | 231 | ||||||
| Net change in capitalized transportation capacity |
(44) | 134 | ||||||
| Impairment charges |
75 | 210 | ||||||
| Gain on sale of the Labrador Island Link Partnership (“LIL”), excluding transaction costs |
- | (191) | ||||||
| Other operating activities, net |
21 | 79 | ||||||
| Changes in non-cash working capital (note 22) |
(382) | 220 | ||||||
| Net cash provided by operating activities |
1,590 | 1,952 | ||||||
| Investing activities |
||||||||
| Additions to PP&E |
(2,566) | (2,223) | ||||||
| Proceeds on disposal of assets |
47 | 6 | ||||||
| Proceeds from disposal of investment subject to significant influence |
- | 927 | ||||||
| Other investing activities |
1 | 1 | ||||||
| Net cash used in investing activities |
(2,518) | (1,289) | ||||||
| Financing activities |
||||||||
| Change in short-term debt, net |
(347) | (83) | ||||||
| Proceeds from short-term debt with maturities greater than 90 days |
500 | - | ||||||
| Proceeds from long-term debt, net of issuance costs |
919 | 1,359 | ||||||
| Retirement of long-term debt |
(176) | (1,082) | ||||||
| Net proceeds (repayments) under committed credit facilities |
485 | (941) | ||||||
| Issuance of common stock, net of issuance costs |
40 | 200 | ||||||
| Dividends on common stock |
(423) | (399) | ||||||
| Dividends on preferred stock |
(56) | (54) | ||||||
| Other financing activities |
(1) | 3 | ||||||
| Net cash provided by (used in) financing activities |
941 | (997) | ||||||
| Effect of exchange rate changes on cash, cash equivalents, restricted cash and cash associated with assets held for sale | (5) | 10 | ||||||
| Net increase (decrease) in cash, cash equivalents, restricted cash, and cash associated with assets held for sale | 8 | (324) | ||||||
| Cash, cash equivalents, restricted cash and cash associated with assets held for sale, beginning of period | 221 | 588 | ||||||
| Cash, cash equivalents, restricted cash and cash associated with assets held for sale, end of period |
$ | 229 | $ | 264 | ||||
| Cash, cash equivalents, restricted cash and cash associated with assets held for sale consists of: | ||||||||
| Cash |
$ | 207 | $ | 235 | ||||
| Short-term investments |
5 | 5 | ||||||
| Restricted cash |
14 | 20 | ||||||
| Cash associated with assets held for sale |
3 | 4 | ||||||
| Total |
$ | 229 | $ | 264 | ||||
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 September 30, 2025 |
| |||||||||||||||||||||||||||
| Balance, June 30, 2025 |
$ | 9,228 | $ | 1,422 | $ | 85 | $ | 660 | $ | 1,755 | $ | 14 | $ | 13,164 | ||||||||||||||
| Net income of Emera Incorporated |
- | - | - | - | 247 | 1 | 248 | |||||||||||||||||||||
| OCI, net of tax expense of $3 million |
- | - | - | 225 | - | - | 225 | |||||||||||||||||||||
| Dividends declared on preferred stock (1) |
- | - | - | - | (19) | - | (19) | |||||||||||||||||||||
| Dividends declared on common stock ($0.7250/share) |
- | - | - | - | (217) | - | (217) | |||||||||||||||||||||
| Issued under the Dividend Reinvestment Program (“DRIP”), net of discounts | 72 | - | - | - | - | - | 72 | |||||||||||||||||||||
| Senior management stock options exercised and Employee Common Share Purchase Plan (“ECSPP”) | 11 | - | - | - | - | - | 11 | |||||||||||||||||||||
| Other |
1 | - | - | - | - | (1) | - | |||||||||||||||||||||
| Balance, September 30, 2025 |
$ | 9,312 | $ | 1,422 | $ | 85 | $ | 885 | $ | 1,766 | $ | 14 | $ | 13,484 | ||||||||||||||
| For the nine months ended September 30, 2025 |
| |||||||||||||||||||||||||||
| Balance, December 31, 2024 |
$ | 9,042 | $ | 1,422 | $ | 84 | $ | 1,261 | $ | 1,468 | $ | 14 | $ | 13,291 | ||||||||||||||
| Net income of Emera Incorporated | - | - | - | - | 1,002 | 1 | 1,003 | |||||||||||||||||||||
| OCI, net of tax recovery of $6 million | - | - | - | (376) | - | - | (376) | |||||||||||||||||||||
| Dividends declared on preferred stock (2) | - | - | - | - | (56) | - | (56) | |||||||||||||||||||||
| Dividends declared on common stock ($2.1750/share) | - | - | - | - | (648) | - | (648) | |||||||||||||||||||||
| Issued under the DRIP, net of discounts | 225 | - | - | - | - | - | 225 | |||||||||||||||||||||
| Issuance of common stock under the at-the-market (“ATM”) program, net of after-tax issuance costs | 10 | - | - | - | - | - | 10 | |||||||||||||||||||||
| Senior management stock options exercised and ECSPP | 34 | - | 1 | - | - | - | 35 | |||||||||||||||||||||
| Other | 1 | - | - | - | - | (1) | - | |||||||||||||||||||||
| Balance, September 30, 2025 |
$ | 9,312 | $ | 1,422 | $ | 85 | $ | 885 | $ | 1,766 | $ | 14 | $ | 13,484 | ||||||||||||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
(1) Series A; $0.1364/share, Series B; $0.2789/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; $0.4092/share, Series B; $0.9451/share, Series C; $1.2064/share, Series E; $0.8438/share, Series F; $0.9813/share; Series H; $1.1858/share; Series J; $0.7969/share and Series L; $0.8625/share
7
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 September 30, 2024 |
| |||||||||||||||||||||||||||
| Balance, June 30, 2024 |
$ | 8,657 | $ | 1,422 | $ | 83 | $ | 656 | $ | 1,729 | $ | 14 | $ | 12,561 | ||||||||||||||
| Net income of Emera Incorporated |
- | - | - | - | 22 | 1 | 23 | |||||||||||||||||||||
| OCI, net of tax recovery of $2 million |
- | - | - | (144) | - | - | (144) | |||||||||||||||||||||
| Dividends declared on preferred stock (1) |
- | - | - | - | (18) | - | (18) | |||||||||||||||||||||
| Dividends declared on common stock ($0.7175/share) |
- | - | - | - | (207) | - | (207) | |||||||||||||||||||||
| Issued under the DRIP, net of discounts |
75 | - | - | - | - | - | 75 | |||||||||||||||||||||
| Issuance of common stock under the ATM program, net of after-tax issuance costs | 146 | - | - | - | - | - | 146 | |||||||||||||||||||||
| Senior management stock options exercised and ECSPP |
6 | - | 1 | - | - | - | 7 | |||||||||||||||||||||
| Other |
- | - | - | - | - | (1) | (1) | |||||||||||||||||||||
| Balance, September 30, 2024 |
$ | 8,884 | $ | 1,422 | $ | 84 | $ | 512 | $ | 1,526 | $ | 14 | $ | 12,442 | ||||||||||||||
| For the nine months ended September 30, 2024 |
| |||||||||||||||||||||||||||
| Balance, December 31, 2023 |
$ | 8,462 | $ | 1,422 | $ | 82 | $ | 305 | $ | 1,803 | $ | 14 | $ | 12,088 | ||||||||||||||
| Net income of Emera Incorporated |
- | - | - | - | 394 | 1 | 395 | |||||||||||||||||||||
| OCI, net of tax expense of $3 million |
- | - | - | 207 | - | - | 207 | |||||||||||||||||||||
| Dividends declared on preferred stock (2) |
- | - | - | - | (54) | - | (54) | |||||||||||||||||||||
| Dividends declared on common stock ($2.1525/share) |
- | - | - | - | (617) | - | (617) | |||||||||||||||||||||
| Issued under the DRIP, net of discount |
217 | - | - | - | - | - | 217 | |||||||||||||||||||||
| Issuance under ATM program, net of after-tax issuance costs | 181 | - | - | - | - | - | 181 | |||||||||||||||||||||
| Senior management stock options exercised and ECSPP |
24 | - | 2 | - | - | - | 26 | |||||||||||||||||||||
| Other |
- | - | - | - | - | (1) | (1) | |||||||||||||||||||||
| Balance, September 30, 2024 |
$ | 8,884 | $ | 1,422 | $ | 84 | $ | 512 | $ | 1,526 | $ | 14 | $ | 12,442 | ||||||||||||||
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
(1) Series A; $0.1364/share, Series B; $0.4298/share, Series C; $0.4021/share, Series E; $0.2813/share, Series F; $0.2626/share; Series H; $0.3953/share; Series J; $0.2656/share and Series L; $0.2875/share
(2) Series A; $0.4092/share, Series B; $1.2948/share, Series C; $1.2064/share, Series E; $0.8438/share, Series F; $0.7879/share; Series H; $1.1858/share; Series J; $0.7969/share and Series L; $0.8625/share
8
Emera Incorporated
Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)
As at September 30, 2025 and 2024
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
Emera Incorporated (“Emera” or the “Company”) is an energy and services company that invests in electricity generation, transmission and distribution, and gas transmission and distribution.
At September 30, 2025, Emera’s reportable segments include the following:
| • | Florida Electric Utility, which consists of Tampa Electric (“TEC”), a vertically integrated regulated electric utility in West Central Florida. |
| • | Canadian Electric Utilities, which includes: |
| • | NSPI, a vertically integrated regulated electric utility and the primary electricity supplier in Nova Scotia; |
| • | a 100 per cent equity interest in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link Project, a $1.8 billion, including AFUDC, transmission project between the island of Newfoundland and Nova Scotia; and |
| • | A 50 per cent indirect voting equity interest in Wasoqonatl Transmission Incorporated (“WTI”), a transmission line project to create a reliability intertie between Nova Scotia and New Brunswick. For more information, refer to note 7. |
| • | Gas Utilities and Infrastructure, which includes: |
| • | Peoples Gas System, Inc. (“PGS”), a regulated gas distribution utility operating across Florida; |
| • | New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility serving customers in New Mexico. On August 5, 2024, Emera announced an agreement to sell NMGC. The transaction is expected to close in early 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; 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. |
9
| • | 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 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a 660 MW pumped storage hydroelectric facility in northwestern Massachusetts. |
| • | Emera US Finance LP, EUSHI Finance, Inc. (“EUSHI Finance”), and TECO Finance, Inc., financing subsidiaries of Emera; |
| • | Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the US; and |
| • | Other investments. |
Basis of Presentation
These unaudited condensed consolidated interim financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”). The significant accounting policies applied to these unaudited condensed consolidated interim financial statements are consistent with those disclosed in the audited consolidated financial statements as at and for the year ended December 31, 2024.
In the opinion of management, these unaudited condensed consolidated interim financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 2025.
All dollar amounts are presented in Canadian dollars, unless otherwise indicated.
Use of Management Estimates
The preparation of unaudited condensed consolidated interim financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. In Q2 2025, the Company recognized a $75 million ($55 million USD), pre-tax, non-cash impairment charge related to the pending sale of NMGC. For more information on the impairment charge, refer to note 3. There were no other material changes in the nature of the Company’s critical accounting estimates from those disclosed in Emera’s 2024 annual audited consolidated financial statements.
10
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 network and servers supporting portions of its business applications. Immediately following detection of the external threat, incident response and business continuity protocols were activated, including the engagement of leading third-party cybersecurity experts. Actions were taken to contain and isolate the affected servers and prevent further intrusion and to notify law enforcement in Canada and the US. There was no disruption to any of the Company’s Canadian physical operations, including at NSPI’s generation, transmission and distribution facilities, the Maritime Link, or the Brunswick Pipeline. There was no impact to Emera’s US or Caribbean utilities’ operations. The post-incident investigation is nearing completion.
The Company implemented business continuity processes for certain impacted business and administrative functions at its Canadian affiliates. The systematic restoration of affected IT systems and corresponding transition away from business continuity processes is progressing and will continue 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.
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.
11
Disaggregation of Income Statement Expenses
In November 2024, the FASB issued ASU 2024-03, Income Statement Reporting – Comprehensive
Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard update improves the disclosures about a public business entity’s expenses by requiring more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation and amortization) included within income statement expense captions. The guidance will be effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The standard updates are to be applied prospectively with the option for retrospective application. The Company is currently evaluating the impact of adoption of the standard update on its consolidated financial statements disclosures.
Improvements to Income Tax Disclosures
In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The standard enhances the transparency, decision usefulness and effectiveness of income tax disclosures by requiring consistent categories and greater disaggregation of information in the reconciliation of income taxes computed using the enacted statutory income tax rate to the actual income tax provision and effective income tax rate, as well as the disaggregation of income taxes paid (refunded) by jurisdiction. The standard also requires disclosure of income (loss) before provision for income taxes and income tax expense (recovery) in accordance with U.S. Securities and Exchange Commission Regulation S-X 210.4-08(h), Rules of General Application – General Notes to Financial Statements: Income Tax Expense, and the removal of disclosures no longer considered cost beneficial or relevant. The guidance will be effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted. The standard will be applied on a prospective basis, with retrospective application permitted. The Company is currently evaluating the impact of adoption of the standard on its consolidated financial statements disclosures.
3. DISPOSITIONS
Pending Sale of NMGC
On August 5, 2024, Emera entered into an agreement to sell its indirect wholly-owned subsidiary NMGC for a total enterprise value of approximately $1.3 billion USD, consisting of cash proceeds and the transfer of debt and customary closing adjustments. As a result of the pending sale, NMGC’s assets and liabilities were classified as held for sale in Q3 2024 and the carrying value of the assets and liabilities were adjusted to FV less cost to sell.
As the transaction proceeds will be lower than the carrying amount of the assets and liabilities being sold,
in Q3 2024 Emera assessed the NMGC reporting unit for goodwill impairment by comparing the FV of expected transaction proceeds to the carrying value of net assets, including goodwill of $366 million USD. The goodwill of the reporting unit was determined to be impaired and a non-cash goodwill impairment charge of $210 million ($198 million, after-tax), or $155 million USD ($146 million USD, after-tax), was recorded in “Impairment charges” on the Condensed Consolidated Statements of Income in Q3 2024.
Following the goodwill impairment assessment, the held for sale assets and liabilities were measured at the lower of their carrying amount or fair value less costs to sell. The measurement resulted in an additional loss for the estimated future transaction costs of $16 million ($13 million after-tax), in addition to
incurred transaction costs of $8 million ($6 million after-tax) recorded in “Other income, net” on the Condensed Consolidated Statements of Income in Q3 2024.
In July 2025, the procedural schedule for the NMPRC regulatory process was revised with the public hearing rescheduled from June 2025 to November 2025. The transaction is expected to close in early 2026.
12
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 (“carrying amount”). On June 30, 2025, the Company remeasured the NMGC disposal group at the lower of its carrying amount and FV less costs to sell. As a result of the change in the expected timing of the transaction close, a non-cash impairment charge of $75 million ($71 million, after-tax), or $55 million USD ($52 million USD, after-tax), was recorded in “Impairment charges” on the Condensed Consolidated Statements of Income in Q2 2025. An additional loss for estimated future transaction costs of $2 million ($1 million after-tax) was recorded in “Other income, net” on the Condensed Consolidated Statements of Income in Q2 2025. There were no additional adjustments recorded in Q3 2025 as a result of the FV less cost to sell assessment performed as at September 30, 2025.
The Company will continue to record depreciation on the NMGC assets through the transaction closing date, as the depreciation continues to be reflected in customer rates and will be reflected in the carryover basis of the assets when sold. Depreciation and amortization of $79 million ($57 million USD) was recorded on these assets from August 5, 2024, the date they were classified as held for sale, through September 30, 2025. Of the $79 million ($57 million USD) recorded to date, $53 million ($38 million USD) was recorded in 2025.
Details of the assets and liabilities classified as held for sale are as follows:
| As at millions of dollars |
September 30 2025 |
December 31 2024 |
||||||
|
|
||||||||
| Cash and cash equivalents |
$ | 3 | $ | 8 | ||||
|
|
||||||||
| Inventory |
9 | 9 | ||||||
|
|
||||||||
| Derivative instruments |
5 | 1 | ||||||
|
|
||||||||
| Regulatory assets |
32 | 28 | ||||||
|
|
||||||||
| Receivables and other current assets |
75 | 127 | ||||||
|
|
||||||||
| Current assets held for sale |
$ | 124 | $ | 173 | ||||
|
|
||||||||
| PP&E |
1,865 | 1,845 | ||||||
|
|
||||||||
| Regulatory assets |
8 | 6 | ||||||
|
|
||||||||
| Goodwill |
292 | 303 | ||||||
|
|
||||||||
| Other long-term assets |
26 | 23 | ||||||
|
|
||||||||
| Less: Adjustment to FV less costs to sell (1) |
(91) | (17) | ||||||
|
|
||||||||
| Long-term assets held for sale |
$ | 2,100 | $ | 2,160 | ||||
|
|
||||||||
| Total assets held for sale |
$ | 2,224 | $ | 2,333 | ||||
|
|
||||||||
| Short-term debt |
$ | 114 | $ | 46 | ||||
|
|
||||||||
| Current portion of long-term debt |
97 | - | ||||||
|
|
||||||||
| Derivative instruments |
- | 1 | ||||||
|
|
||||||||
| Regulatory liabilities |
15 | 10 | ||||||
|
|
||||||||
| Accounts payable and other current liabilities |
97 | 155 | ||||||
|
|
||||||||
| Current liabilities associated with assets held for sale |
323 | 212 | ||||||
|
|
||||||||
| Long-term debt |
576 | 696 | ||||||
|
|
||||||||
| Deferred income taxes |
189 | 167 | ||||||
|
|
||||||||
| Regulatory liabilities |
265 | 274 | ||||||
|
|
||||||||
| Other long-term liabilities |
7 | 11 | ||||||
|
|
||||||||
| Long-term liabilities associated with assets held for sale |
$ | 1,037 | $ | 1,148 | ||||
|
|
||||||||
| Total liabilities associated with assets held for sale |
$ | 1,360 | $ | 1,360 | ||||
|
|
||||||||
(1) Represents a $75 million impairment charge related to the remeasurement of the NMGC disposal group to FV (December 31, 2024 - nil) and $16 million in estimated transaction costs related to the pending sale (December 31, 2024 – $17 million).
13
Sale of LIL Equity Interest
On June 4, 2024, Emera completed the sale of its 31.1 per cent indirect minority equity interest in the LIL for a total transaction value of $1.2 billion, including cash proceeds of $957 million and $235 million for assuming Emera’s contractual obligation to fund the remaining initial capital investment, which represents additional LIL equity interest for the acquirer. Cash proceeds from the sale in the amount of $30 million is held in escrow pending finalization of certain agreements with the LIL general partner. The escrow proceeds receivable is held at FV and included in the gain on sale, after transaction costs. As of September 30, 2025, the estimated FV of the escrow proceeds receivable is $25 million. In Q2 2024, a gain on sale, after transaction costs, of $182 million ($107 million, after tax and transaction costs), was recognized in “Other income, net” on the Condensed Consolidated Statements of Income and included in the Other segment.
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.
14
| 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 September 30, 2025 |
| |||||||||||||||||||||||||||
| Operating revenues from external customers (1) | $ | 1,266 | $ | 405 | $ | 314 | $ | 159 | $ | (38 | ) | $ | - | $ | 2,106 | |||||||||||||
|
|
||||||||||||||||||||||||||||
| Inter-segment revenues (1) | 3 | - | 5 | - | 7 | (15 | ) | - | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Total operating revenues |
1,269 | 405 | 319 | 159 | (31 | ) | (15 | ) | 2,106 | |||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Regulated fuel for generation and purchased power | 281 | 189 | - | 83 | - | (6 | ) | 547 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Regulated cost of natural gas | - | - | 53 | - | - | - | 53 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| OM&G | 315 | 98 | 113 | 36 | 25 | (9 | ) | 578 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Provincial, state and municipal taxes | 84 | 12 | 26 | 1 | 1 | - | 124 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Depreciation and amortization | 176 | 74 | 52 | 21 | 1 | - | 324 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Income from equity investments | - | 10 | 4 | 1 | - | - | 15 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other income, net | 19 | 11 | 3 | 3 | (17 | ) | - | 19 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Interest expense, net (2) | 79 | 45 | 37 | 5 | 94 | - | 260 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Income tax expense (recovery) | 51 | (5 | ) | 13 | - | (53 | ) | - | 6 | |||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| NCI | - | - | - | 1 | - | - | 1 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Preferred stock dividends | - | - | - | - | 19 | - | 19 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 302 | $ | 13 | $ | 32 | $ | 16 | $ | (135 | ) | $ | - | $ | 228 | |||||||||||||
|
|
||||||||||||||||||||||||||||
| For the nine months ended September 30, 2025 |
| |||||||||||||||||||||||||||
| Operating revenues from external customers (1) | $ | 3,353 | $ | 1,440 | $ | 1,282 | $ | 435 | $ | 260 | $ | - | $ | 6,770 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
| Inter-segment revenues (1) | 8 | - | 13 | - | 23 | (44 | ) | - | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Total operating revenues |
3,361 | 1,440 | 1,295 | 435 | 283 | (44 | ) | 6,770 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Regulated fuel for generation and purchased power | 772 | 671 | - | 223 | - | (13 | ) | 1,653 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Regulated cost of natural gas | - | - | 346 | - | - | - | 346 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| OM&G | 821 | 327 | 350 | 110 | 90 | (25 | ) | 1,673 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Provincial, state and municipal taxes | 237 | 37 | 86 | 3 | 1 | - | 364 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Depreciation and amortization | 523 | 221 | 152 | 58 | 5 | - | 959 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Income from equity investments | - | 32 | 14 | 3 | (1 | ) | - | 48 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other income, net | 66 | 25 | 9 | 5 | 24 | 6 | 135 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Interest expense, net (2) | 226 | 129 | 112 | 15 | 282 | - | 764 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Impairment charges | - | - | - | - | 75 | - | 75 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Income tax expense (recovery) | 122 | (39 | ) | 72 | 3 | (42 | ) | - | 116 | |||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| NCI | - | - | - | 1 | - | - | 1 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Preferred stock dividends | - | - | - | - | 56 | - | 56 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 726 | $ | 151 | $ | 200 | $ | 30 | $ | (161 | ) | $ | - | $ | 946 | |||||||||||||
|
|
||||||||||||||||||||||||||||
| As at September 30, 2025 |
| |||||||||||||||||||||||||||
| Total assets | $ | 24,747 | $ | 8,131 | $ | 8,477 | $ | 1,439 | $ | 1,882 | $ | (873 | ) | $ | 43,803 | |||||||||||||
|
|
||||||||||||||||||||||||||||
| Investments subject to significant influence | $ | - | $ | 470 | $ | 112 | $ | 55 | $ | - | $ | - | $ | 637 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
| Goodwill | $ | 4,871 | $ | - | $ | 796 | $ | - | $ | - | $ | - | $ | 5,667 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
(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 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 September 30, 2025, and $20 million for the nine months ended September 30, 2025 between the Gas Utilities and Infrastructure and Other segments.
15
| 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 September 30, 2024 |
| |||||||||||||||||||||||||||
| Operating revenues from external customers (1) | $ | 985 | $ | 399 | $ | 297 | $ | 150 | $ | (29 | ) | $ | - | $ | 1,802 | |||||||||||||
| Inter-segment revenues (1) | 3 | - | 3 | - | (8 | ) | 2 | - | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Total operating revenues |
988 | 399 | 300 | 150 | (37 | ) | 2 | 1,802 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Regulated fuel for generation and purchased power | 224 | 185 | - | 78 | - | (3 | ) | 484 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Regulated cost of natural gas | - | - | 46 | - | - | - | 46 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| OM&G | 196 | 87 | 103 | 39 | 12 | (5 | ) | 432 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Provincial, state and municipal taxes | 73 | 12 | 24 | 1 | - | - | 110 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Depreciation and amortization | 156 | 71 | 46 | 18 | 2 | - | 293 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Income from equity investments | - | 12 | 4 | 1 | 8 | - | 25 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other income (expenses), net | 15 | 7 | 5 | 2 | (5 | ) | (10 | ) | 14 | |||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Interest expense, net (2) | 66 | 41 | 38 | 5 | 91 | - | 241 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Impairment charges | - | - | 11 | - | 210 | - | 221 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Income tax expense (recovery) | 36 | (4 | ) | 11 | - | (52 | ) | - | (9 | ) | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| NCI | - | - | - | 1 | - | - | 1 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Preferred stock dividends | - | - | - | - | 18 | - | 18 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 252 | $ | 26 | $ | 30 | $ | 11 | $ | (315 | ) | $ | - | $ | 4 | |||||||||||||
|
|
||||||||||||||||||||||||||||
| For the nine months ended September 30, 2024 |
| |||||||||||||||||||||||||||
| Operating revenues from external customers (1) | $ | 2,639 | $ | 1,376 | $ | 1,150 | $ | 416 | $ | (144 | ) | $ | - | $ | 5,437 | |||||||||||||
| Inter-segment revenues (1) | 7 | - | 10 | - | 10 | (27 | ) | - | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Total operating revenues |
2,646 | 1,376 | 1,160 | 416 | (134 | ) | (27 | ) | 5,437 | |||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Regulated fuel for generation and purchased power | 641 | 639 | - | 217 | - | (10 | ) | 1,487 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Regulated cost of natural gas | - | - | 282 | - | - | - | 282 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| OM&G | 587 | 299 | 333 | 106 | 105 | (15 | ) | 1,415 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Provincial, state and municipal taxes | 207 | 36 | 78 | 3 | 1 | - | 325 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Depreciation and amortization | 462 | 209 | 135 | 54 | 6 | - | 866 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Income from equity investments | - | 67 | 14 | 3 | 3 | - | 87 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other income, net | 44 | 21 | 12 | 7 | 146 | 2 | 232 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Interest expense, net (2) | 197 | 126 | 115 | 16 | 271 | - | 725 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Impairment charges | - | - | 11 | - | 210 | - | 221 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Income tax expense (recovery) | 72 | - | 60 | - | (92 | ) | - | 40 | ||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| NCI | - | - | - | 1 | - | - | 1 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Preferred stock dividends | - | - | - | - | 54 | - | 54 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 524 | $ | 155 | $ | 172 | $ | 29 | $ | (540 | ) | $ | - | $ | 340 | |||||||||||||
|
|
||||||||||||||||||||||||||||
| As at December 31, 2024 |
| |||||||||||||||||||||||||||
| Total assets | $ | 24,375 | $ | 7,609 | $ | 8,439 | $ | 1,444 | $ | 1,810 | $ | (726) | $ | 42,951 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
| Investment subject to significant influence | $ | - | $ | 475 | $ | 124 | $ | 55 | $ | - | $ | - | $ | 654 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
| Goodwill | $ | 5,035 | $ | - | $ | 823 | $ | - | $ | - | $ | - | $ | 5,858 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E, OM&G, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are measured at the amount of consideration established 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 $8 million for the three months ended September 30, 2024, and $22 million for the nine months ended September 30, 2024 between the Gas Utilities and Infrastructure and Other segments.
16
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 September 30, 2025 |
| |||||||||||||||||||||||||||||||
| Regulated Revenue |
||||||||||||||||||||||||||||||||
| Residential |
$ | 787 | $ | 197 | $ | 59 | $ | 116 | $ | - | $ | - | $ | 1,159 | ||||||||||||||||||
| Commercial |
323 | 122 | 81 | 103 | - | - | 629 | |||||||||||||||||||||||||
| Industrial |
71 | 68 | 7 | 26 | - | (6) | 166 | |||||||||||||||||||||||||
| Other electric |
117 | 10 | 2 | - | - | - | 129 | |||||||||||||||||||||||||
| Regulatory deferrals |
(35) | - | 7 | - | - | - | (28) | |||||||||||||||||||||||||
| Other (1) |
6 | 8 | 3 | 52 | - | (3) | 66 | |||||||||||||||||||||||||
| Finance income (2)(3) |
- | - | - | 16 | - | - | 16 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Regulated revenue |
1,269 | 405 | 159 | 313 | - | (9) | 2,137 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Non-Regulated Revenue |
||||||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
- | - | - | - | (3) | - | (3) | |||||||||||||||||||||||||
| Other non-regulated operating revenue |
- | - | - | 6 | 9 | (8) | 7 | |||||||||||||||||||||||||
| Mark-to-market (3) |
- | - | - | - | (37) | 2 | (35) | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 6 | (31) | (6) | (31) | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Total operating revenues |
$ | 1,269 | $ | 405 | $ | 159 | $ | 319 | $ | (31) | $ | (15) | $ | 2,106 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| For the nine months ended September 30, 2025 |
| |||||||||||||||||||||||||||||||
| Regulated Revenue |
||||||||||||||||||||||||||||||||
| Residential |
$ | 1,909 | $ | 788 | $ | 152 | $ | 568 | $ | - | $ | - | $ | 3,417 | ||||||||||||||||||
| Commercial |
858 | 390 | 231 | 395 | - | - | 1,874 | |||||||||||||||||||||||||
| Industrial |
205 | 203 | 21 | 76 | - | (14) | 491 | |||||||||||||||||||||||||
| Other electric |
384 | 32 | 6 | - | - | - | 422 | |||||||||||||||||||||||||
| Regulatory deferrals |
(13) | - | 16 | - | - | - | 3 | |||||||||||||||||||||||||
| Other (1) |
18 | 27 | 9 | 190 | - | (8) | 236 | |||||||||||||||||||||||||
| Finance income (2)(3) |
- | - | - | 48 | - | - | 48 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Regulated revenue |
3,361 | 1,440 | 435 | 1,277 | - | (22) | 6,491 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Non-Regulated Revenue |
||||||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
- | - | - | - | 98 | - | 98 | |||||||||||||||||||||||||
| Other non-regulated operating revenue |
- | - | - | 18 | 25 | (21) | 22 | |||||||||||||||||||||||||
| Mark-to-market (3) |
- | - | - | - | 160 | (1) | 159 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 18 | 283 | (22) | 279 | |||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Total operating revenues |
$ | 3,361 | $ | 1,440 | $ | 435 | $ | 1,295 | $ | 283 | $ | (44) | $ | 6,770 | ||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
(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.
17
| 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 September 30, 2024 |
| |||||||||||||||||||||||||||||||
| Regulated Revenue |
||||||||||||||||||||||||||||||||
| Residential |
$ | 643 | $ | 191 | $ | 56 | $ | 107 | $ | - | $ | - | $ | 997 | ||||||||||||||||||
| Commercial |
258 | 118 | 78 | 97 | - | - | 551 | |||||||||||||||||||||||||
| Industrial |
56 | 70 | 9 | 24 | - | (4) | 155 | |||||||||||||||||||||||||
| Other electric |
101 | 10 | 1 | - | - | - | 112 | |||||||||||||||||||||||||
| Regulatory deferrals |
(76) | - | 5 | - | - | - | (71) | |||||||||||||||||||||||||
| Other (1) |
6 | 10 | 1 | 51 | - | (3) | 65 | |||||||||||||||||||||||||
| Finance income (2)(3) |
- | - | - | 16 | - | - | 16 | |||||||||||||||||||||||||
| Regulated revenue |
988 | 399 | 150 | 295 | - | (7) | 1,825 | |||||||||||||||||||||||||
| Non-Regulated Revenue |
||||||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
- | - | - | - | (7) | - | (7) | |||||||||||||||||||||||||
| Other non-regulated operating revenue |
- | - | - | 5 | 7 | (5) | 7 | |||||||||||||||||||||||||
|
Mark-to-market (3) |
- | - | - | - | (37) | 14 | (23) | |||||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 5 | (37) | 9 | (23) | |||||||||||||||||||||||||
| Total operating revenues |
$ | 988 | $ | 399 | $ | 150 | $ | 300 | $ | (37) | $ | 2 | $ | 1,802 | ||||||||||||||||||
| For the nine months ended September 30, 2024 |
| |||||||||||||||||||||||||||||||
| Regulated Revenue |
||||||||||||||||||||||||||||||||
| Residential |
$ | 1,580 | $ | 737 | $ | 149 | $ | 499 | $ | - | $ | - | $ | 2,965 | ||||||||||||||||||
| Commercial |
710 | 371 | 224 | 361 | - | - | 1,666 | |||||||||||||||||||||||||
| Industrial |
168 | 207 | 22 | 71 | - | (11) | 457 | |||||||||||||||||||||||||
| Other electric |
318 | 31 | 4 | - | - | - | 353 | |||||||||||||||||||||||||
| Regulatory deferrals |
(145) | - | 13 | - | - | - | (132) | |||||||||||||||||||||||||
| Other (1) |
15 | 30 | 4 | 167 | - | (7) | 209 | |||||||||||||||||||||||||
| Finance income (2)(3) |
- | - | - | 47 | - | - | 47 | |||||||||||||||||||||||||
| Regulated revenue |
2,646 | 1,376 | 416 | 1,145 | - | (18) | 5,565 | |||||||||||||||||||||||||
| Non-Regulated Revenue |
||||||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
- | - | - | - | 42 | - | 42 | |||||||||||||||||||||||||
| Other non-regulated operating revenue |
- | - | - | 15 | 22 | (16) | 21 | |||||||||||||||||||||||||
|
Mark-to-market (3) |
- | - | - | - | (198) | 7 | (191) | |||||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 15 | (134) | (9) | (128) | |||||||||||||||||||||||||
| Total operating revenues |
$ | 2,646 | $ | 1,376 | $ | 416 | $ | 1,160 | $ | (134) | $ | (27) | $ | 5,437 | ||||||||||||||||||
(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, lighting contracts, and long-term steam supply arrangements with fixed contract terms. As of September 30, 2025, the aggregate amount of the transaction price allocated to remaining performance obligations was $452 million (2024 – $453 million), including $14 million related to NMGC. This amount includes $124 million of future performance obligations related to a gas transportation contract between SeaCoast and PGS through 2040. This amount excludes contracts with an original expected length of one year or less and variable amounts for which Emera recognizes revenue at the amount to which it has the right to invoice for services performed. Emera expects to recognize revenue for the remaining performance obligations through 2045.
18
6. REGULATORY ASSETS AND LIABILITIES
A summary of regulatory assets and liabilities is provided below. For a detailed description regarding the nature of the Company’s regulatory assets and liabilities, refer to note 7 in Emera’s 2024 annual audited consolidated financial statements. Updates to regulatory environments are included below.
| As at millions of dollars |
September 30 2025 |
December 31 2024 |
||||||||||
|
|
||||||||||||
| Regulatory assets (1) |
||||||||||||
| Deferred income tax regulatory assets |
$ | 1,287 | $ | 1,227 | ||||||||
| TEC capital cost recovery for early retired assets |
732 | 737 | ||||||||||
| Pension and post-retirement medical plan |
376 | 395 | ||||||||||
| Storm cost recovery clauses |
322 | 613 | ||||||||||
| TEC capital cost recovery for retired Polk Unit 1 components |
185 | 205 | ||||||||||
| NSPI FAM |
67 | - | ||||||||||
| Cost recovery clauses |
57 | 33 | ||||||||||
| Deferrals related to derivative instruments |
36 | 42 | ||||||||||
| Environmental remediations |
27 | 29 | ||||||||||
| Stranded cost recovery |
26 | 27 | ||||||||||
| Other (2) |
117 | 119 | ||||||||||
| $ | 3,232 | $ | 3,427 | |||||||||
| Current |
$ | 500 | $ | 595 | ||||||||
| Long-term |
2,732 | 2,832 | ||||||||||
| Total regulatory assets |
$ | 3,232 | $ | 3,427 | ||||||||
| Regulatory liabilities (1) |
||||||||||||
| Deferred income tax regulatory liabilities |
$ | 775 | $ | 828 | ||||||||
| Accumulated reserve – cost of removal |
722 | 733 | ||||||||||
| Cost recovery clauses |
84 | 121 | ||||||||||
| BLPC Self-insurance fund (“SIF”) (note 23) |
31 | 32 | ||||||||||
| Deferrals related to derivative instruments |
22 | 44 | ||||||||||
| NSPI FAM |
- | 56 | ||||||||||
| Other (2) |
67 | 66 | ||||||||||
| $ | 1,701 | $ | 1,880 | |||||||||
| Current |
$ | 218 | $ | 262 | ||||||||
| Long-term |
1,483 | 1,618 | ||||||||||
| Total regulatory liabilities |
$ | 1,701 | $ | 1,880 | ||||||||
(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
Base Rates:
On September 4, 2025, TEC petitioned the Florida Public Service Commission (“FPSC”) to increase base revenue by $88 million USD to reflect the 2026 adjustment in accordance with its 2024 rate case decision. On November 4, 2025, the FPSC approved the adjustment, with new rates becoming effective January 1, 2026.
On February 3, 2025, the FPSC issued the final order approving the rate case decision, effective January 1, 2025. In February 2025, a motion for reconsideration on certain aspects of the final order was filed by an intervening party with the FPSC. On May 6, 2025, the FPSC denied the motion for reconsideration, except with respect to immaterial calculation corrections, and the final order was issued on June 11, 2025. In March 2025, two intervening parties each filed a notice of appeal to the Florida Supreme Court regarding the outcome of TEC’s 2024 base rate proceeding. To date, the intervening parties have not filed their briefs related to the appeal.
19
Storm Reserve:
On February 4, 2025, the FPSC approved TEC’s petition for the recovery of $466 million USD of costs associated with Hurricane Idalia, Hurricane Debby, Hurricane Helene and Hurricane Milton, and the associated interest to replenish the storm reserve over an 18-month recovery period, which began in March 2025. The amount of cost-recovery is subject to a true-up mechanism with the FPSC.
Canadian Electric Utilities
NSPI
Base Rates:
On September 18, 2025, NSPI filed a consensus General Rate Application (“GRA”) with the Nova Scotia Energy Board (“NSEB”), formerly the Nova Scotia Utility and Review Board, reflecting a settlement agreement reached with customer representatives. The settlement reflects more than six months of discussion, consultation, and information sharing. The GRA proposes average annual rate increases of 1.8 per cent in 2026 and 2.4 per cent in 2027. The proposed rates would result in annual revenue (fuel and non-fuel) increases of $62 million in 2026 and $108 million in 2027. The hearing for the matter is scheduled for January 2026.
NSPML
On July 18, 2025, NSPML submitted an application to the NSEB requesting recovery of approximately $199 million in Maritime Link costs for 2026.
On November 29, 2024, NSPML received approval from the NSEB, to collect up to $197 million in 2025 from NSPI. Payments from NSPI are subject to a holdback of up to $4 million per month. There was no holdback recorded in 2025 year-to-date.
Gas Utilities and Infrastructure
PGS
Base Rates:
On March 31, 2025, PGS filed a rate case with the FPSC for new rates to become effective January 1, 2026. On August 13, 2025, PGS and the intervening parties filed a settlement agreement with the FPSC for a $67 million USD increase in 2026 annual base rates, which includes $7 million USD from the cast iron and bare steel replacement rider, and additional adjustments of $25 million USD in 2027 and up to $5 million USD in 2028 (subject to FPSC approval). This reflects a 10.30 per cent midpoint ROE and 54.7 per cent equity thickness. On October 31, 2025, the FPSC issued the final order approving the settlement, effective January 1, 2026.
20
7. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME
| September 30 | Carrying Value as at December 31 |
Equity Income for the three months ended September 30 |
Equity Income (loss) for the nine months ended September 30 |
Percentage of Ownership |
||||||||||||||||||||||||
| millions of dollars |
2025 | 2024 | 2025 | 2024 | 2025 | 2024 | 2025 | |||||||||||||||||||||
| NSPML |
$ | 470 | $ | 475 | $ | 10 | $ | 12 | $ | 32 | $ | 38 | 100.0 | |||||||||||||||
| M&NP (1) |
112 | 124 | 4 | 4 | 14 | 14 | 12.9 | |||||||||||||||||||||
| Lucelec (1) |
55 | 55 | 1 | 1 | 3 | 3 | 19.5 | |||||||||||||||||||||
| LIL (2) |
- | - | - | - | - | 29 | - | |||||||||||||||||||||
| Bear Swamp (3) |
- | - | - | 8 | (1) | 3 | 50.0 | |||||||||||||||||||||
| WTI (4) |
- | - | - | - | - | - | 50.0 | |||||||||||||||||||||
| $ | 637 | $ | 654 | $ | 15 | $ | 25 | $ | 48 | $ | 87 | |||||||||||||||||
(1) Emera has significant influence over the operating and financial decisions of these companies through Board representation and therefore, records its investment in these entities using the equity method.
(2) On June 4, 2024, Emera completed the sale of its equity interest in the LIL. For further details, refer to note 3.
(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 $90 million (December 31, 2024 – $92 million) is recorded in Other long-term liabilities on the Condensed Consolidated Balance Sheets.
(4) On March 5, 2025, NSPI, the Canada Infrastructure Bank (“CIB”) and the Wskijinu’k Mtmo’taqnuow Agency (“WMA”) announced the Wasoqonatl transmission line project to create a reliability intertie between Nova Scotia and New Brunswick. The project will be owned by a new regulated utility, WTI, which is wholly-owned by a newly formed limited partnership between NSPI, CIB and WMA. NSPI will be responsible for providing construction, operation, maintenance and administrative services to WTI. NSPI has a 50 per cent indirect voting interest in WTI. As of September 30, 2025, NSPI’s investment was nominal.
Emera accounts for its variable interest investment in NSPML as an equity investment (note 23). NSPML’s consolidated summarized balance sheet is as follows:
| As at millions of dollars |
September 30 2025 |
December 31 2024 |
||||||
| Current assets |
$ | 69 | $ | 37 | ||||
| PP&E |
1,386 | 1,425 | ||||||
| Regulatory assets |
785 | 778 | ||||||
| Non-current assets |
27 | 27 | ||||||
| Total assets |
$ | 2,267 | $ | 2,267 | ||||
| Current liabilities |
$ | 91 | $ | 55 | ||||
| Long-term debt (1) |
1,524 | 1,570 | ||||||
| Non-current liabilities |
182 | 167 | ||||||
| Equity |
470 | 475 | ||||||
| Total liabilities and equity |
$ | 2,267 | $ | 2,267 | ||||
(1) The project debt has been guaranteed by the Government of Canada.
8. OTHER INCOME, NET
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| AFUDC - equity |
$ | 12 | $ | 15 | $ | 49 | $ | 36 | ||||||||
| Interest income |
8 | 4 | 28 | 13 | ||||||||||||
| Pension non-service cost recovery |
7 | 8 | 21 | 26 | ||||||||||||
| FX (losses) gains |
(17) | 6 | 23 | (16) | ||||||||||||
| Transaction costs related to the pending sale of NMGC (1) |
- | (24) | (2) | (24) | ||||||||||||
| Gain on sale of LIL, after transaction costs (1) |
- | - | - | 182 | ||||||||||||
| Other |
9 | 5 | 16 | 15 | ||||||||||||
| $ | 19 | $ | 14 | $ | 135 | $ | 232 | |||||||||
(1) For more information related to the gain on sale, after transaction costs, of Emera’s indirect minority equity interest in the LIL and the pending sale of NMGC, refer to note 3.
21
9. INCOME TAXES
The income tax provision differs from that computed using the enacted combined Canadian federal and provincial statutory income tax rate for the following reasons:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| Income before provision for income taxes |
$ | 254 | $ | 14 | $ | 1,119 | $ | 435 | ||||||||
| Statutory income tax rate |
29% | 29% | 29% | 29% | ||||||||||||
| Income taxes, at statutory income tax rate |
74 | 4 | 325 | 126 | ||||||||||||
| Tax credits |
(28) | (22) | (93) | (47) | ||||||||||||
| Amortization of deferred income tax regulatory liabilities |
(14) | (14) | (35) | (30) | ||||||||||||
| Foreign tax rate variance | (14) | (11) | (35) | (26) | ||||||||||||
| Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities | (3) | (8) | (34) | (38) | ||||||||||||
| Impairment charges |
- | 48 | 18 | 48 | ||||||||||||
| Valuation allowance |
(5) | - | (15) | - | ||||||||||||
| Tax effect of equity earnings |
(2) | (4) | (10) | (12) | ||||||||||||
| Additional impact from the sale of LIL equity interest |
- | - | - | 22 | ||||||||||||
| Other |
(2) | (2) | (5) | (3) | ||||||||||||
| Income tax expense (recovery) |
$ | 6 | $ | (9) | $ | 116 | $ | 40 | ||||||||
| Effective income tax rate |
2% | (64%) | 10% | 9% | ||||||||||||
US One Big Beautiful Bill Act (“OBBBA”):
On July 4, 2025, the OBBBA was signed into law. The OBBBA makes permanent many of the expired and expiring tax provisions originally enacted in the Tax Cuts and Jobs Act of 2017. It also includes significant changes in future years to the timing and availability of several clean energy tax credits previously enacted in the Inflation Reduction Act, including the investment tax credit and production tax credit. On August 15, 2025, the Internal Revenue Service released guidance on determining when projects have begun construction for purposes of qualifying for these tax credits. Emera is currently evaluating the impact of the enacted changes. To date in 2025, the OBBBA has not had an impact on the Company.
10. COMMON STOCK
Authorized: Unlimited number of non-par value common shares.
| Issued and outstanding: | millions of shares | millions of dollars | ||||||
| Balance, December 31, 2024 |
295.94 | $ | 9,042 | |||||
| Conversion of Convertible Debentures |
0.02 | 1 | ||||||
| Issuance of common stock under ATM program (1) |
0.19 | 10 | ||||||
| Issued under the DRIP, net of discounts |
3.80 | 225 | ||||||
| Senior management stock options exercised and ECSPP |
0.65 | 34 | ||||||
| Balance, September 30, 2025 |
300.60 | $ | 9,312 | |||||
(1) For the three months ended September 30, 2025, no common shares were issued under Emera’s ATM program. For the nine months ended September 30, 2025, a total of 187,600 common shares were issued under Emera’s ATM program at an average price of $53.58 per share for gross proceeds of $10 million ($10 million net of after-tax issuance costs). As at September 30, 2025, an aggregate gross sales limit of $326 million remained available for issuance under the ATM program, which expired on November 4, 2025.
22
11. EARNINGS PER SHARE
The following table reconciles the computation of basic and diluted earnings per share:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars (except per share amounts) | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| Numerator |
||||||||||||||||
| Net income attributable to common shareholders |
$ | 227.5 | $ | 3.7 | $ | 945.9 | $ | 339.9 | ||||||||
| Diluted numerator |
227.5 | 3.7 | 945.9 | 339.9 | ||||||||||||
| Denominator |
||||||||||||||||
| Weighted average shares of common stock outstanding – basic |
299.9 | 290.0 | 298.5 | 287.5 | ||||||||||||
| Stock-based compensation |
0.7 | 0.1 | 0.5 | 0.1 | ||||||||||||
| Weighted average shares of common stock outstanding – diluted |
300.6 | 290.1 | 299.0 | 287.6 | ||||||||||||
| Earnings per common share |
||||||||||||||||
| Basic |
$ | 0.76 | $ | 0.01 | $ | 3.17 | $ | 1.18 | ||||||||
| Diluted |
$ | 0.76 | $ | 0.01 | $ | 3.16 | $ | 1.18 | ||||||||
12. 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 nine months ended September 30, 2025 |
| |||||||||||||||||||||||
| Balance, January 1, 2025 |
$ | 1,396 | $ | (163) | $ | 12 | $ | - | $ | 16 | $ | 1,261 | ||||||||||||
| OCI before reclassifications |
(428) | 56 | - | 1 | - | (371) | ||||||||||||||||||
| Amounts reclassified from AOCI |
- | - | (2) | - | (3) | (5) | ||||||||||||||||||
| Net current period OCI |
(428) | 56 | (2) | 1 | (3) | (376) | ||||||||||||||||||
| Balance, September 30, 2025 |
$ | 968 | $ | (107) | $ | 10 | $ | 1 | $ | 13 | $ | 885 | ||||||||||||
| For the nine months ended September 30, 2024 |
| |||||||||||||||||||||||
| Balance, January 1, 2024 |
$ | 369 | $ | (24) | $ | 14 | $ | (2) | $ | (52) | $ | 305 | ||||||||||||
| OCI before reclassifications |
240 | (33) | - | 1 | - | 208 | ||||||||||||||||||
| Amounts reclassified from AOCI |
- | - | (2) | - | 1 | (1) | ||||||||||||||||||
| Net current period OCI |
240 | (33) | (2) | 1 | 1 | 207 | ||||||||||||||||||
| Balance, September 30, 2024 |
$ | 609 | $ | (57) | $ | 12 | $ | (1) | $ | (51) | $ | 512 | ||||||||||||
The reclassifications out of AOCI are as follows:
| Three months ended | Nine months ended | |||||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||||
| millions of dollars | 2025 | 2024 | 2025 | 2024 | ||||||||||||||
| Affected line item in the Condensed Consolidated Interim Financial Statements |
Amounts reclassified from AOCI | |||||||||||||||||
| Gain on derivatives recognized as cash flow hedges | ||||||||||||||||||
| Interest rate hedge |
Interest expense, net | $ | (1) | $ | (1) | $ | (2) | $ | (2) | |||||||||
| Net change in unrecognized pension and post-retirement benefit costs |
| |||||||||||||||||
| Amounts reclassified into obligations |
Pension and post-retirement benefits | 1 | - | (3) | 1 | |||||||||||||
| Total reclassifications out of AOCI, for the period |
$ | - | $ | (1) | $ | (5) | $ | (1) | ||||||||||
23
13. 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. |
24
Derivative assets and liabilities relating to the foregoing categories consisted of the following:
| Derivative Assets | Derivative Liabilities | |||||||||||||||
| As at | September 30 | December 31 | September 30 | December 31 | ||||||||||||
| millions of dollars | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
$ | 21 | $ | 25 | $ | 37 | $ | 44 | ||||||||
| FX forwards |
7 | 27 | - | 3 | ||||||||||||
| 28 | 52 | 37 | 47 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
41 | 34 | 39 | 30 | ||||||||||||
| Natural gas swaps, futures, forwards, physical contracts |
292 | 236 | 593 | 660 | ||||||||||||
| 333 | 270 | 632 | 690 | |||||||||||||
| Other derivatives: |
||||||||||||||||
| Equity derivatives |
36 | - | - | 2 | ||||||||||||
| FX forwards |
5 | - | 6 | 34 | ||||||||||||
| 41 | - | 6 | 36 | |||||||||||||
| Total gross derivatives |
402 | 322 | 675 | 773 | ||||||||||||
| Impact of master netting agreements: |
||||||||||||||||
| Regulatory deferral |
(1) | (7) | (1) | (7) | ||||||||||||
| HFT derivatives |
(127) | (148) | (127) | (148) | ||||||||||||
| Total impact of master netting agreements |
(128) | (155) | (128) | (155) | ||||||||||||
| Less: Derivatives classified as held for sale (1) |
(5) | (1) | - | (1) | ||||||||||||
| Total derivatives |
$ | 269 | $ | 166 | $ | 547 | $ | 617 | ||||||||
| Current (2) |
221 | 115 | 473 | 526 | ||||||||||||
| Long-term (2) |
48 | 51 | 74 | 91 | ||||||||||||
| Total derivatives |
$ | 269 | $ | 166 | $ | 547 | $ | 617 | ||||||||
(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 note 3.
(2) Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.
Cash Flow Hedges
On May 26, 2021, a treasury lock was settled for a gain of $19 million that is being amortized through interest expense over 10 years as the underlying hedged item settles. As of September 30, 2025, the unrealized gain in AOCI was $10 million, after-tax (December 31, 2024 – $12 million, after-tax). For the three and nine months ended September 30, 2025, unrealized gains of $1 million (2024 - $1 million) and $2 million (2024 - $2 million) respectively were reclassified from AOCI into interest expense, net. The Company expects $2 million of unrealized gains currently in AOCI to be reclassified into net income within the next twelve months.
25
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 September 30 |
2025 | 2024 | ||||||||||||||
| Unrealized (loss) gain in regulatory assets |
$ | (17) | $ | 4 | $ | (14) | $ | (1) | ||||||||
| Unrealized (loss) gain in regulatory liabilities |
(7) | 6 | (6) | (1) | ||||||||||||
| Realized gain in regulatory assets |
(2) | - | (3) | - | ||||||||||||
| Realized loss in regulatory liabilities |
2 | - | 1 | - | ||||||||||||
| Realized loss (gain) loss in inventory (1) |
3 | (1) | 3 | (1) | ||||||||||||
| Realized loss (gain) in regulated fuel for generation and purchased power (2) | 7 | (1) | 16 | (1) | ||||||||||||
| Total change in derivative instruments |
$ | (14) | $ | 8 | $ | (3) | $ | (4) | ||||||||
|
|
||||||||||||||||
| For the nine months ended September 30 |
2025 | 2024 | ||||||||||||||
| Unrealized (loss) gain in regulatory assets |
$ | (32) | $ | 3 | $ | (1) | $ | - | ||||||||
| Unrealized gain (loss) in regulatory liabilities |
10 | (12) | 6 | 13 | ||||||||||||
| Realized gain in regulatory assets |
(5) | - | (7) | - | ||||||||||||
| Realized loss in regulatory liabilities |
5 | - | 1 | - | ||||||||||||
| Realized loss (gain) in inventory (1) |
10 | (5) | 10 | (5) | ||||||||||||
| Realized loss (gain) in regulated fuel for generation and purchased power (2) |
15 | (3) | 41 | (5) | ||||||||||||
| Total change in derivative instruments | $ | 3 | $ | (17) | $ | 50 | $ | 3 | ||||||||
(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.
(2) Realized (gains) losses on derivative instruments settled and consumed in the period and hedging relationships that have been terminated or the hedged transaction is no longer probable.
As at September 30, 2025, the Company had the following notional volumes designated for regulatory deferral that are expected to settle as outlined below:
| millions | 2025 | 2026-2027 | ||||||
| Commodity swaps and forwards purchases: |
||||||||
| Natural gas (MMBtu) |
2 | 19 | ||||||
| Power (MWh) |
- | 1 | ||||||
| FX forwards: |
||||||||
| FX contracts (millions of USD) |
$ | 67 | $ | 203 | ||||
| Weighted average rate |
1.3422 | 1.3546 | ||||||
| % of USD requirements |
80% | 40% | ||||||
HFT Derivatives
The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives:
| Three months ended | Nine months ended | |||||||||||||||
| For the | September 30 | September 30 | ||||||||||||||
| millions of dollars | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| Power swaps and physical contracts in non-regulated operating revenues | $ | 3 | $ | - | $ | 3 | $ | 11 | ||||||||
| Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues | 13 | 59 | 477 | 198 | ||||||||||||
| Total gains in net income |
$ | 16 | $ | 59 | $ | 480 | $ | 209 | ||||||||
26
As at September 30, 2025, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:
| millions | 2025 | 2026 | 2027 | 2028 | 2029 and thereafter |
|||||||||||||||
| Natural gas purchases (MMBtu) |
156 | 391 | 137 | 56 | 74 | |||||||||||||||
| Natural gas sales (MMBtu) |
179 | 385 | 89 | 16 | 9 | |||||||||||||||
| Power purchases (MWh) |
1 | 1 | - | - | - | |||||||||||||||
| Power sales (MWh) |
1 | 1 | 1 | - | - | |||||||||||||||
Other Derivatives
As at September 30, 2025, the Company had equity derivatives in place to manage cash flow risk associated with forecasted future cash settlements of deferred compensation obligations and FX forwards in place to manage cash flow risk associated with forecasted USD cash inflows. The equity derivatives hedge the return on 2.9 million shares and extends until December 2025. The FX forwards have a combined notional amount of $403 million USD and expire in 2025 through 2026.
The Company has recognized the following realized and unrealized gains (losses) with respect to other derivatives:
| millions of dollars |
FX forwards |
Equity derivatives |
FX forwards |
Equity derivatives |
||||||||||||
| For the three months ended September 30 | 2025 | 2024 | ||||||||||||||
| Unrealized gain in OM&G | $ | - | $ | 11 | $ | - | $ | 22 | ||||||||
| Unrealized (loss) gain in other income, net | (14) | - | 8 | - | ||||||||||||
| Realized loss in other income, net | (2) | - | (3) | - | ||||||||||||
| Total (losses) gains in net income | $ | (16) | $ | 11 | $ | 5 | $ | 22 | ||||||||
| For the nine months ended September 30 | 2025 | 2024 | ||||||||||||||
| Unrealized gain in OM&G | $ | - | $ | 36 | $ | - | $ | 8 | ||||||||
| Unrealized gain (loss) in other income, net | 33 | - | (8) | - | ||||||||||||
| Realized loss in other income, net | (12) | - | (7) | - | ||||||||||||
| Total gains (losses) in net income |
$ | 21 | $ | 36 | $ | (15) | $ | 8 | ||||||||
Credit Risk
The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits, and derivative assets. Credit risk is the potential loss from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral are requested on any high-risk accounts.
The Company assesses the potential for credit losses on a regular basis and, where appropriate, maintains provisions. With respect to counterparties, the Company has implemented procedures to monitor the creditworthiness and credit exposure of counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in default probability rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the Company’s current default probability. Net asset positions are adjusted based on the counterparty’s current default probability. The Company internally assesses credit risk for counterparties that are not rated.
27
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 September 30, 2025, the Company had $178 million (December 31, 2024 – $140 million) in financial assets considered to be past due, which had been outstanding for an average 64 days. The FV of these financial assets was $165 million (December 31, 2024 – $128 million), the difference of which is included in the allowance for credit losses. These assets primarily relate to accounts receivable from electric and gas revenue.
Cash Collateral
The Company’s cash collateral positions consisted of the following:
| As at millions of dollars |
September 30 2025 |
December 31 2024 |
||||||
| Cash collateral provided to others |
$ | 141 | $ | 198 | ||||
| Cash collateral received from others |
$ | 8 | $ | 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 September 30, 2025, the total FV of derivatives in a liability position was $547 million (December 31, 2024 – $617 million). If the credit ratings of the Company were reduced below investment grade, the full value of the net liability position could be required to be posted as collateral for these derivatives.
14. FV MEASUREMENTS
The Company is required to determine the FV of all derivatives except those which qualify for the NPNS exemption (see note 13) 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.
28
Level 3 – Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally developed inputs. The primary reasons for a Level 3 classification are as follows:
| • | While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials. |
| • | The term of certain transactions extends beyond the period when quoted prices are available, and accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term. |
| • | The valuations of certain transactions were based on internal models, although quoted prices were utilized in the valuations. |
Derivative assets and liabilities are classified in their entirety, based on the lowest level of input that is significant to the FV measurement.
The following tables set out the classification of the methodology used by the Company to FV its derivatives:
| As at | September 30, 2025 | |||||||||||||||
| millions of dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Assets |
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
$ | 15 | $ | 5 | $ | - | $ | 20 | ||||||||
| FX forwards |
- | 7 | - | 7 | ||||||||||||
| 15 | 12 | - | 27 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
- | 27 | 5 | 32 | ||||||||||||
| Natural gas swaps, futures, forwards, physical contracts and related transportation |
3 | 133 | 38 | 174 | ||||||||||||
| 3 | 160 | 43 | 206 | |||||||||||||
| Other derivatives: |
||||||||||||||||
| FX forwards |
- | 5 | - | 5 | ||||||||||||
| Equity derivatives |
36 | - | - | 36 | ||||||||||||
| 36 | 5 | - | 41 | |||||||||||||
| Less: Derivatives classified as held for sale (1) |
- | (5) | - | (5) | ||||||||||||
| Total assets |
54 | 172 | 43 | 269 | ||||||||||||
| Liabilities |
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
15 | 21 | - | 36 | ||||||||||||
| 15 | 21 | - | 36 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
(2) | 27 | 4 | 29 | ||||||||||||
| Natural gas swaps, futures, forwards and physical contracts |
(8) | 110 | 374 | 476 | ||||||||||||
| (10) | 137 | 378 | 505 | |||||||||||||
| Other derivatives: |
||||||||||||||||
| FX forwards |
- | 6 | - | 6 | ||||||||||||
| - | 6 | - | 6 | |||||||||||||
| Total liabilities |
5 | 164 | 378 | 547 | ||||||||||||
| Net assets (liabilities) |
$ | 49 | $ | 8 | $ | (335) | $ | (278) | ||||||||
(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 note 3.
29
| As at | December 31, 2024 | |||||||||||||||
| millions of dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Assets |
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
$ | 15 | $ | 3 | $ | - | $ | 18 | ||||||||
| FX forwards |
- | 27 | - | 27 | ||||||||||||
| 15 | 30 | - | 45 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
2 | 23 | 5 | 30 | ||||||||||||
| Natural gas swaps, futures, forwards, physical contracts and related transportation |
13 | 52 | 27 | 92 | ||||||||||||
| 15 | 75 | 32 | 122 | |||||||||||||
| Less: Derivatives classified as held for sale (1) |
- | (1) | - | (1) | ||||||||||||
| Total assets |
30 | 104 | 32 | 166 | ||||||||||||
| Liabilities |
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
18 | 19 | - | 37 | ||||||||||||
| FX forwards |
- | 3 | - | 3 | ||||||||||||
| 18 | 22 | - | 40 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
2 | 21 | 4 | 27 | ||||||||||||
| Natural gas swaps, futures, forwards and physical contracts |
(11) | 89 | 437 | 515 | ||||||||||||
| (9) | 110 | 441 | 542 | |||||||||||||
| Other derivatives: |
||||||||||||||||
| FX forwards |
- | 34 | - | 34 | ||||||||||||
| Equity derivatives |
2 | - | - | 2 | ||||||||||||
| 2 | 34 | - | 36 | |||||||||||||
| Less: Derivatives classified as held for sale (1) |
- | (1) | - | (1) | ||||||||||||
| Total liabilities |
11 | 165 | 441 | 617 | ||||||||||||
| Net assets (liabilities) |
$ | 19 | $ | (61) | $ | (409) | $ | (451) | ||||||||
(1) On August 4, 2024, Emera announced an agreement to sell NMGC. As 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 note 3.
The change in the FV of the Level 3 financial assets and liabilities was as follows:
| Three months ended | Nine months ended | |||||||||||||||||||||||
| September 30, 2025 | September 30, 2025 | |||||||||||||||||||||||
|
HFT Derivatives |
HFT Derivatives |
|||||||||||||||||||||||
| millions of dollars | Power | Natural gas |
Total | Power | Natural gas |
Total | ||||||||||||||||||
| Assets |
||||||||||||||||||||||||
| Balance, beginning of period |
$ | 5 | $ | 27 | $ | 32 | $ | 5 | $ | 27 | $ | 32 | ||||||||||||
| Total realized and unrealized gains or losses included in non-regulated operating revenues | - | 11 | 11 | - | 11 | 11 | ||||||||||||||||||
| Balance, September 30, 2025 |
$ | 5 | $ | 38 | $ | 43 | $ | 5 | $ | 38 | $ | 43 | ||||||||||||
| Liabilities |
||||||||||||||||||||||||
| Balance, beginning of period |
$ | 5 | $ | 293 | $ | 298 | $ | 4 | $ | 437 | $ | 441 | ||||||||||||
| Total realized and unrealized gains or losses included in non-regulated operating revenues | (1) | 81 | 80 | - | (63) | (63) | ||||||||||||||||||
| Balance, September 30, 2025 |
$ | 4 | $ | 374 | $ | 378 | $ | 4 | $ | 374 | $ | 378 | ||||||||||||
30
Significant unobservable inputs used in the FV measurement of Emera’s natural gas and power derivatives include third-party sourced pricing for instruments based on illiquid markets. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) FV measurement. Other unobservable inputs used include internally developed correlation factors and basis differentials; own credit risk; and discount rates. Internally developed correlations and basis differentials are reviewed on a quarterly basis based on statistical analysis of the spot markets in the various illiquid term markets. Discount rates may include a risk premium for those long-term forward contracts with illiquid future price points to incorporate the inherent uncertainty of these points. Any risk premiums for long-term contracts are evaluated by observing similar industry practices and in discussion with industry peers.
The Company uses a modelled pricing valuation technique for determining the FV of Level 3 derivative instruments. The following table outlines quantitative information about the significant unobservable inputs used in the FV measurements categorized within Level 3 of the FV hierarchy:
| September 30, 2025 | ||||||||||||||||||||||
| As at millions of dollars |
FV | Significant Unobservable Input |
Low | High | Weighted Average (1) |
|||||||||||||||||
| Assets | Liabilities | |||||||||||||||||||||
| HFT derivatives – Power swaps and physical contracts | 5 | 4 | Third-party pricing | $ | 27.50 | $ | 144.40 | $79.09 | ||||||||||||||
| HFT derivatives – Natural gas swaps, futures, forwards and physical contracts | 38 | 374 | Third-party pricing | $0.69 | $15.54 | $8.64 | ||||||||||||||||
| Total |
$ | 43 | $ | 378 | ||||||||||||||||||
| Net liability |
$ | 335 | ||||||||||||||||||||
(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 | ||||||||||||||||||
| September 30, 2025 |
$ | 18,979 | $ | 18,314 | $ | - | $ | 17,911 | $ | 403 | $ | 18,314 | ||||||||||||
| December 31, 2024 |
$ | 18,407 | $ | 17,941 | $ | - | $ | 17,688 | $ | 253 | $ | 17,941 | ||||||||||||
The Company has designated $1.2 billion USD denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in USD denominated operations. An after-tax foreign currency loss of $33 million was recorded in AOCI for the three months ended September 30, 2025 (2024 – $22 million after-tax gain) and an after-tax foreign currency gain of $56 million was recorded for the nine months ended September 30, 2025 (2024 – $33 million after-tax loss).
31
15. RELATED PARTY TRANSACTIONS
In the ordinary course of business, Emera provides energy and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Intercompany balances and intercompany transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities, in accordance with accounting standards for rate-regulated entities. All material amounts are under normal interest and credit terms.
Significant transactions between Emera and its associated companies are as follows:
| • | Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Condensed Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $49 million for the three months ended September 30, 2025 (2024 – $41 million) and $140 million for the nine months ended September 30, 2025 (2024 – $123 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 $1 million for the three months ended September 30, 2025 (2024 – $2 million) and $12 million for the nine months ended September 30, 2025 (2024 – $8 million). |
| • | On March 5, 2025, NSPI sold development assets associated with the Wasoqonatl transmission line project to WTI for consideration of $15 million. The development assets were sold at cost with no gain or loss recognized in the Condensed Consolidated Statements of Income. |
As at September 30, 2025, Emera and its associated companies had $41 million due to related parties (December 31, 2024 – $24 million) recorded in “Other Current Liabilities” on the Condensed Consolidated Balance Sheets.
16. RECEIVABLES AND OTHER CURRENT ASSETS
| As at millions of dollars |
September 30 2025 |
December 31 2024 |
||||||
|
|
||||||||
| Customer accounts receivable – billed |
$ 963 | $ 834 | ||||||
|
|
||||||||
| Customer accounts receivable – unbilled |
370 | 342 | ||||||
|
|
||||||||
| Capitalized transportation capacity (1) |
246 | 216 | ||||||
|
|
||||||||
| Cash collateral provided to others |
142 | 198 | ||||||
|
|
||||||||
| Prepaid expenses |
133 | 105 | ||||||
|
|
||||||||
| Income tax receivable |
49 | 22 | ||||||
|
|
||||||||
| Allowance for credit losses |
(13) | (12) | ||||||
|
|
||||||||
| Other |
215 | 106 | ||||||
|
|
||||||||
| Total receivables and other current assets |
$ 2,105 | $ 1,811 | ||||||
|
|
||||||||
(1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract.
32
17. 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 September 30 |
Nine months ended September 30 |
||||||||||||||
| millions of dollars | 2025 | 2024 | 2025 | 2024 | ||||||||||||
|
|
||||||||||||||||
| DB pension plans |
||||||||||||||||
| Service cost |
$ | 9 | $ | 9 | $ | 27 | $ | 26 | ||||||||
|
|
||||||||||||||||
| Non-service cost: |
||||||||||||||||
| Interest cost |
29 | 27 | 86 | 82 | ||||||||||||
|
|
||||||||||||||||
| Expected return on plan assets |
(40) | (40) | (122) | (120) | ||||||||||||
|
|
||||||||||||||||
| Current year amortization of: |
||||||||||||||||
| Actuarial losses |
- | - | 1 | 1 | ||||||||||||
|
|
||||||||||||||||
| Regulatory asset |
2 | 3 | 7 | 7 | ||||||||||||
|
|
||||||||||||||||
| Total non-service costs |
(9) | (10) | (28) | (30) | ||||||||||||
|
|
||||||||||||||||
| Total DB pension plans |
- | (1) | (1) | (4) | ||||||||||||
|
|
||||||||||||||||
| Non-pension benefit plans |
||||||||||||||||
| Service cost |
- | 1 | 2 | 2 | ||||||||||||
|
|
||||||||||||||||
| Non-service cost: |
||||||||||||||||
| Interest cost |
3 | 3 | 9 | 9 | ||||||||||||
|
|
||||||||||||||||
| Expected return on plan assets |
(1) | (1) | (2) | (2) | ||||||||||||
|
|
||||||||||||||||
| Current year amortization of: |
||||||||||||||||
| Regulatory asset |
- | (1) | - | (3) | ||||||||||||
|
|
||||||||||||||||
| Past service costs |
- | - | (1) | - | ||||||||||||
|
|
||||||||||||||||
| Total non-service costs |
2 | 1 | 6 | 4 | ||||||||||||
|
|
||||||||||||||||
| Total non-pension benefit plans |
2 | 2 | 8 | 6 | ||||||||||||
|
|
||||||||||||||||
| Total DB plans |
$ | 2 | $ | 1 | $ | 7 | $ | 2 | ||||||||
|
|
||||||||||||||||
Emera’s pension and non-pension contributions related to these DB plans for the three months ended September 30, 2025 were $20 million (2024 – $13 million), and for the nine months ended September 30, 2025 were $47 million (2024 – $41 million). Annual employer contributions to the DB pension plans are estimated to be $41 million for 2025. Emera’s contributions related to the DC plans for the three months ended September 30, 2025 were $13 million (2024 – $12 million) and $41 million (2024 – $37 million) for the nine months ended September 30, 2025.
18. SHORT-TERM DEBT
Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non-revolving credit facilities and short-term notes. For details regarding short-term debt, refer to note 24 in Emera’s 2024 annual audited consolidated financial statements, and below for 2025 short-term debt financing activity.
Canadian Electric Utilities
On May 21, 2025, NSPI entered into a $500 million non-revolving facility which matures on May 21, 2026. The credit agreement contains customary representations and warranties, events of default and financial and other covenants. The non-revolving facility’s interest rates are referenced to the Term CORRA or prime rate, plus a margin.
33
Gas Utilities and Infrastructure
On October 23, 2025, NMGC entered into a $70 million USD, 364-day term loan agreement which matures on October 22, 2026. The credit agreement contains customary representations and warranties, events of default and financial and other covenants. The non-revolving facility’s interest rates are referenced to the Term SOFR plus a margin.
On September 19, 2025, NMGC amended its $125 million USD unsecured committed revolving credit facility to extend the maturity date from December 17, 2026, to December 17, 2027. There were no other changes in commercial terms from the prior agreement.
Other
On February 20, 2025, Emera amended its $200 million unsecured non-revolving facility to extend the maturity date from February 19, 2025 to February 19, 2026. There were no other material changes to the terms from the prior agreement.
19. LONG-TERM DEBT
For details regarding long-term debt, refer to note 26 in Emera’s 2024 annual audited consolidated financial statements, and below for 2025 long-term debt financing activity.
Florida Electric Utility
On March 6, 2025, TEC issued $600 million USD of senior unsecured notes that bear interest at 5.15 per cent with a maturity date of March 1, 2035.
Other
On September 25, 2025, EUSHI Finance, Emera US Holdings Inc. and Emera filed a 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 of one or more series of senior and/or subordinated unsecured debt securities (“Debt Securities”), in an aggregate principal amount of up to $3 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 October 3, 2025, EUSHI Finance completed an issuance of $750 million USD fixed-to-fixed reset rate junior subordinated notes, pursuant to the prospectus supplement dated September 29, 2025, to the Base Shelf Prospectus. The notes initially bear interest at a rate of 6.25 per cent, and will reset on April 1, 2031, and every five years thereafter, to a rate per annum equal to the five-year US treasury rate plus 2.509 per cent, subject to an interest rate floor of 6.25 per cent. The notes mature on April 1, 2056. EUSHI Finance, at its option, may redeem the notes, in whole or in part, 90 days prior to the first interest reset date, and any semi-annual interest payment date thereafter, at a redemption price equal to the principal amount, plus accrued and unpaid interest on the notes to be redeemed, in accordance with the terms of the prospectus supplement; and otherwise, at the times and the redemption prices described in the prospectus supplement. The notes are fully and unconditionally guaranteed, on a joint, several and subordinated basis, by Emera, and Emera US Holdings Inc.
34
20. COMMITMENTS AND CONTINGENCIES
A. Commitments
As at September 30, 2025, contractual commitments (excluding pensions and other post-retirement obligations, long-term debt and asset retirement obligations) for each of the next five years and in aggregate thereafter consisted of the following:
| millions of dollars | 2025 | 2026 | 2027 | 2028 | 2029 | Thereafter | Total | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Purchased power (1) |
$ | 89 | $ | 316 | $ | 406 | $ | 396 | $ | 445 | $ | 5,951 | $ | 7,603 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
| Transportation (2)(3) |
241 | 725 | 578 | 466 | 407 | 3,122 | 5,539 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Fuel, gas supply and storage (4) |
227 | 660 | 130 | 45 | 40 | 99 | 1,201 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Capital projects |
342 | 149 | 40 | 5 | 2 | - | 538 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other |
42 | 72 | 58 | 50 | 48 | 264 | 534 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| $ | 941 | $ | 1,922 | $ | 1,212 | $ | 962 | $ | 942 | $ | 9,436 | $ | 15,415 | |||||||||||||||
|
|
||||||||||||||||||||||||||||
As detailed below, commitments at September 30, 2025 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 $124 million related to a gas transportation contract between PGS and SeaCoast through 2040.
(3) Includes $65 million related to NMGC (2025: $11 million, 2026: $23 million, 2027: $15 million, 2028: $12 million, 2029: $4 million).
(4) Includes $186 million related to NMGC (2025: $53 million, 2026: $117 million, 2027: $13 million, 2028: $3 million).
NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. In November 2024, the NSEB approved the collection of up to $197 million from NSPI for the recovery of Maritime Link costs in 2025. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to NSEB approval.
Emera has committed to obtain certain transmission rights in New Brunswick during summer periods (April through October, inclusive) for Newfoundland and Labrador Hydro’s use, if requested, effective August 15, 2021 and continuing for 50 years. As transmission rights are contracted, the obligations are included within “Other” in the above table.
B. Legal Proceedings
Superfund and Former Manufactured Gas Plant Sites
Previously, TEC had been a potentially responsible party (“PRP”) for certain superfund sites through its Tampa Electric and former PGS divisions, as well as for certain former manufactured gas plant sites through its PGS division. As a result of the separation of the PGS division into a separate legal entity, Peoples Gas System, Inc. is also now a PRP for those sites (in addition to third party PRPs for certain sites). While the aggregate joint and several liability associated with these sites has not changed as a result of the PGS legal separation, the sites continue to present the potential for significant response costs. As at September 30, 2025, the aggregate financial liability of the Florida utilities is estimated to be $16 million ($12 million USD), primarily at PGS. This estimate assumes that other involved PRPs are credit-worthy entities. This amount has been accrued and is primarily reflected in the long-term liability section under “Other long-term liabilities” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.
The estimated amounts represent only the portion of the cleanup costs attributable to the Florida utilities. The estimates to perform the work are based on the Florida utilities’ experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.
35
In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-worthy and are likely to continue to be credit-worthy for the duration of the remediation work. However, in those instances that they are not, the Florida utilities could be liable for more than their actual percentage of the remediation costs. Other factors that could impact these estimates include additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in base rate proceedings.
Other Legal Proceedings
Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company.
C. Principal Financial Risks and Uncertainties
For information on principal financial risks which could materially affect the Company in the normal course of business, refer to note 28 in Emera’s 2024 annual audited consolidated financial statements. Risks associated with derivative instruments and FV measurements are discussed in note 13 and note 14. There have been no material changes to the principal financial risks as of September 30, 2025.
D. Guarantees and Letters of Credit
Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2024 audited annual consolidated financial statements, with material updates as noted below:
Emera, on behalf of Brunswick Pipeline, issued a standby letter of credit for $22 million to secure obligations under a non-revolving loan agreement. This standby letter of credit has a one-year term, expiring on March 31, 2026, and will be renewed annually, as required.
The Company has standby letters of credit and surety bonds in the amount of $136 million USD (December 31, 2024 – $105 million USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed annually, as required.
Emera, on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The expiry date of this letter of credit was extended to June 2026. The amount committed as at September 30, 2025 was $70 million (December 31, 2024 – $58 million).
21. CUMULATIVE PREFERRED STOCK
For details regarding cumulative preferred stock, refer to note 29 in Emera’s 2024 annual audited consolidated financial statements, and below for 2025 preferred stock activity.
On July 9, 2025, Emera announced that it would not redeem the currently outstanding Cumulative 5-Year Rate Reset Preferred Shares, Series A (“Series A Shares”) or the Cumulative Floating Rate First Preferred Shares, Series B (“Series B Shares”) on August 15, 2025 (the “Conversion Date”).
On July 16, 2025, Emera announced a dividend rate of 4.951 per cent per annum on the Series A Shares during the five-year period commencing on August 15, 2025 and ending on (and inclusive of) August 14, 2030 ($0.3094 per Series A Share per quarter).
36
During the conversion period between July 16, 2025 and July 31, 2025, the holders of Series A Shares had the right, at their option, to convert all or any of their Series A Shares, on a one-for-one basis, into Series B Shares and the holders of Series B Shares had the right, at their option, to convert all or any of their Series B Shares, on a one-for-one basis, into Series A Shares. On August 7, 2025, Emera announced, after having taken into account all shares tendered for conversion by holders of its Series A Shares and Series B Shares, as the case may be (collectively, the “Holders”), by the end of the conversion period, the Company has determined that there would be outstanding on the Conversion Date less than 1 million Series B Shares. Therefore, in accordance with certain rights, privileges, restrictions and conditions attaching to the Series A Shares and the Series B Shares, the Company advised the Holders that no Series A Shares would be converted into Series B Shares and all remaining Series B Shares would automatically be converted into Series A Shares on a one-for-one basis on the Conversion Date. On the Conversion Date, there were 6 million Series A Shares and no Series B Shares outstanding.
22. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
| For the | Nine months ended September 30 | |||||||
| millions of dollars | 2025 | 2024 | ||||||
|
|
||||||||
| Changes in non-cash working capital: |
||||||||
| Inventory |
$ | (84) | $ | 44 | ||||
|
|
||||||||
| Receivables and other current assets |
(230) | 155 | ||||||
|
|
||||||||
| Accounts payable |
(169) | (64) | ||||||
|
|
||||||||
| Other current liabilities |
101 | 85 | ||||||
|
|
||||||||
| Total non-cash working capital |
$ | (382) | $ | 220 | ||||
|
|
||||||||
| Supplemental disclosure of non-cash activities: |
||||||||
| Common share dividends reinvested |
$ | 225 | $ | 217 | ||||
|
|
||||||||
| Increase in accrued capital expenditures |
$ | 28 | $ | 12 | ||||
|
|
||||||||
| Accrued proceeds from disposal of investment subject to significant influence |
$ | - | $ | 25 | ||||
|
|
||||||||
| Supplemental disclosure of operating activities: |
||||||||
| Net change in short-term regulatory assets and liabilities |
$ | 217 | $ | 216 | ||||
|
|
||||||||
23. VARIABLE INTEREST ENTITIES
Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since it does not have controlling financial interest of NSPML. When the critical milestones were achieved, Newfoundland and Labrador Hydro was deemed the primary beneficiary of the asset for financial reporting purposes, as it has authority over the majority of the direct activities expected to most significantly impact the economic performance of the Maritime Link. Thus, Emera began recording the Maritime Link as an equity investment.
BLPC established a SIF, primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission, and distribution systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered that, in substance, activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. Any withdrawal of SIF fund assets by the Company would be subject to existing regulations. Emera’s consolidated VIE in the SIF is recorded as “Other long-term assets”, “Restricted cash” and “Regulatory liabilities” on the Condensed Consolidated Balance Sheets. Amounts included in restricted cash represent the cash portion of funds required to be set aside for the BLPC SIF.
37
The Company has identified certain long-term purchase power agreements that meet the definition of variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions.
The following table provides information about Emera’s portion of material unconsolidated VIEs:
| As at | September 30, 2025 | December 31, 2024 | ||||||||||||||
|
|
||||||||||||||||
| millions of dollars | Total assets |
Maximum exposure to loss |
Total assets |
Maximum exposure to loss |
||||||||||||
|
|
||||||||||||||||
| Unconsolidated VIEs in which Emera has variable interests |
||||||||||||||||
| NSPML (equity accounted) |
$ | 470 | $ | 6 | $ | 475 | $ | 6 | ||||||||
|
|
||||||||||||||||
24. 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 November 7, 2025, the date the unaudited condensed consolidated interim financial statements were issued.
38
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 the nine months ended September 30, 2025.
The following earnings coverage ratio is calculated on a consolidated basis for the twelve months ended September 30, 2025.
| Twelve months ended September 30, 2025 | ||
| Earnings Coverage (1) |
1.83 |
(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 $104 million for the twelve months ended September 30, 2025. Emera’s interest requirements for the twelve months ended September 30, 2025 amounted to $1,044 million. Emera’s consolidated income before interest and income tax for the twelve months ended September 30, 2025 was $2,105 million, which is 1.83 times Emera’s aggregate preferred dividends and interest requirements for this period.
Exhibit 99.4
Emera Reports 2025 Third Quarter Financial Results and Unveils $20 Billion Five-Year Capital Plan
HALIFAX, Nova Scotia – Today, November 7, 2025, Emera Inc. (“Emera”) (TSX/NYSE: EMA) reported financial results for the third quarter and year-to-date 2025 and released details about its 2026-2030 capital plan.
Highlights
| • | Delivered 9% improvement in adjusted earnings per share1 (“EPS”) for the third quarter of 2025, with $0.88 of adjusted EPS and $0.76 of reported EPS. |
| • | Introduced 5-year $20 billion capital plan and extended 7-8% rate base growth guidance through 2030 with approximately 80% directed towards investment in Florida. |
| • | Completed the Peoples Gas rate case process, providing regulatory clarity through 2028. Nova Scotia Power reached a settlement agreement with customer representatives, and a consensus rate case was filed with the regulator in mid-September. |
| • | Deployed more than $2.6 billion in capital year-to-date and remain on track to fully execute our 2025 capital plan. |
“Emera’s momentum continues with another strong quarter of adjusted EPS1 growth, principally driven by continued strong operational performance at Tampa Electric. We also saw significant progress on the regulatory front with the completion of the Peoples Gas rate case,” said Scott Balfour, President and CEO of Emera Inc. “We are extending our 7-8% rate base growth through 2030, supported by a $20 billion capital plan that focuses on enhancing customer reliability. This includes investments in grid modernization, gas infrastructure and technology updates that will support ongoing growth, with a specific focus on Florida.”
5-Year Capital and Funding Plan Overview
| • | Five-year $20 billion capital and funding plan extends 7-8% rate base growth guidance through 2030. |
| • | Emera’s capital plan is primarily directed toward investments in Florida, with nearly 80% allocated to the region focused on strengthening and storm hardening systems and supporting continued growth, while continuing to deliver an 8-9% expected rate base growth for its Florida utilities. |
1
| • | The majority of capital plan – more than 90% - is allocated to reliability and grid modernization projects; renewable asset integration (for greater reliability and more predictable customer costs); and technological innovation (including increased investments in cybersecurity and artificial intelligence). |
| • | 55% of investments specifically focused on strengthening electric transmission, distribution, and gas infrastructure systems to support reliability and customer growth. |
Q3 2025 Financial Results
Q3 2025 adjusted net income1 was $263 million, or $0.88 per common share, compared with $236 million, or $0.81 per common share, in Q3 2024. The increase was primarily due to increased earnings at Tampa Electric (“TEC”), partially offset by lower earnings at Nova Scotia Power (“NSPI”) and New Mexico Gas Company (“NMGC”) and higher corporate costs.
Q3 2025 reported net income was $228 million, or $0.76 per common share, compared with net income of $4 million, or $0.01 per common share, in Q3 2024, primarily driven by the $225 million in charges related to the pending sale of NMGC recognized in Q3 2024, and increased earnings at TEC. These were partially offset by $28 million increase in mark-to-market (“MTM”) losses, lower earnings at NSPI and NMGC, and higher corporate costs.
Year-to-date Financial Results
Year-to-date adjusted net income1 was $878 million or $2.94 per common share, compared with $603 million or $2.10 per common share year-to-date in 2024. Year-to-date adjusted net income increased $275 million primarily due to increased earnings at TEC, Emera Energy Services (“EES”), NSPI, and NMGC; and decreased corporate costs. These were partially offset by lower equity earnings resulting from last year’s sale of Emera’s interest in the Labrador Island Link (“LIL”).
Year-to-date reported net income was $946 million or $3.17 per common share, compared with net income of $340 million or $1.18 per common share, year-to-date in 2024. Year-to-date reported net income included a $140 million MTM gain, after-tax, compared to a $145 million MTM loss, after-tax in 2024, and $72 million in charges related to the pending sale of NMGC, after-tax. Year-to-date reported income for 2024 included a $107 million gain, after tax and transaction costs, on the sale of Emera’s equity interest in LIL in Q2 2024 and $225 million in charges related to the pending sale of NMGC in Q3 2024.
The translation impact of a weaker CAD on USD earnings increased adjusted net income by $1 million in Q3 2025 and $16 million year-to-date compared to the same periods in 2024.
2
In Q3 2025, the impact of a weaker CAD on US denominated earnings was more than offset by the realized and unrealized losses on FX hedges used to mitigate the translation risk of USD earnings, resulting in a $10 million decrease to net income attributable to common shareholders compared to the same period in 2024. Year-to-date 2025, the impact of a weaker CAD on US denominated earnings increased net income attributable to common shareholders by $52 million compared to the same period in 2024. Impacts of the changes in the translation of the CAD include the impacts of Corporate FX hedges used to mitigate translation risk of USD earnings in the Other segment.
| (1) | See “Non-GAAP Financial Measures and Ratios” noted below and “Segment Results and Non-GAAP Reconciliation” below for reconciliation to nearest USGAAP measure. |
3
Segment Results and Non-GAAP Reconciliation
| For the | Three months ended September 30 |
Nine months ended September 30 |
||||||||||||||
| millions of Canadian dollars (except per share amounts) | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| Adjusted net income 1,2 |
||||||||||||||||
| Florida Electric Utility |
$ | 302 | $ | 252 | 726 | 524 | ||||||||||
| Canadian Electric Utilities |
13 | 26 | 151 | 155 | ||||||||||||
| Gas Utilities and Infrastructure |
32 | 38 | 200 | 180 | ||||||||||||
| Other Electric Utilities |
16 | 10 | 28 | 27 | ||||||||||||
| Other 3 |
(100) | (90) | (227) | (283) | ||||||||||||
|
|
||||||||||||||||
| Adjusted net income1,2 |
$ | 263 | $ | 236 | 878 | 603 | ||||||||||
|
|
||||||||||||||||
| Charges related to the pending sale of NMGC, after-tax 4,5 |
- | (225) | (72) | (225) | ||||||||||||
| Gain on sale of LIL, after-tax 6 |
- | - | - | 107 | ||||||||||||
| MTM (loss) gain, after-tax7 |
(35) | (7) | 140 | (145) | ||||||||||||
|
|
||||||||||||||||
| Net income attributable to common shareholders |
$ | 228 | $ | 4 | 946 | 340 | ||||||||||
|
|
||||||||||||||||
| EPS (basic) |
$ | 0.76 | $ | 0.01 | 3.17 | 1.18 | ||||||||||
|
|
||||||||||||||||
| Adjusted EPS (basic) 1,2 |
$ | 0.88 | $ | 0.81 | 2.94 | 2.10 | ||||||||||
|
|
||||||||||||||||
1 See “Non-GAAP Financial Measures and Ratios” noted below.
2 Excludes the charges related to the pending sale of NMGC, after-tax, gain on sale of LIL, after-tax, and the effect of after-tax MTM adjustments.
3 Lower earnings, quarter-over-quarter, primarily results from higher operating, maintenance and general expenses (“OM&G”), partially offset by higher income tax recovery. Higher earnings year-over-year due to higher contributions from EES, lower OM&G and higher income tax recovery, partially offset higher interest expense.
4 Represents (i) a $71 million non-cash impairment charge, after-tax, and $1 million in transaction costs, after-tax for the nine months ended September 30, 2025 and (ii) $206 million in non-cash goodwill and other impairment charges, after-tax and $19 million in transaction costs, after-tax for the three and nine months ended September 30, 2024.
5 Net of income tax recovery of nil for the three months ended September 30, 2025 (2024 - $20 million) and $5 million for the nine months ended September 30, 2025 (2024 - $20 million).
6 Net of income tax expense of $75 million for the nine months ended September 30, 2024.
7 Net of income tax recovery of $15 million for the three months ended September 30, 2025 (2024 – $4 million recovery) and $56 million income tax expense for the nine months ended September 30, 2025 (2024 – $60 million recovery).
4
Consolidated Financial Review
The following table highlights significant quarter-over-quarter and year-over-year changes in adjusted net income from 2024 to 2025:
| For the millions of Canadian dollars |
Three months ended September 30 |
Nine months ended September 30 |
||||||
| Adjusted net income – 2024 1,2 |
$ | 236 | $ | 603 | ||||
|
|
||||||||
| Operating Unit Performance |
||||||||
| Increased earnings at TEC due to higher revenue from new base rates and customer growth, partially offset by increased OM&G, depreciation expenses, interest and income tax expense. Year-over-year the increase was also due to the impact of favourable weather and the impact of a weaker CAD | 50 | 202 | ||||||
| Decreased income from equity investments due to the sale of equity interest in LIL in Q2 2024 | - | (28) | ||||||
| Increased earnings at EES year-over-year due to favourable weather and resulting market conditions in Q1 2025 (higher natural gas prices and increased volatility) | (1) | 33 | ||||||
| Increased earnings year-over-year at NMGC due to higher revenue from new base rates and the impact of a weaker CAD | (4) | 22 | ||||||
| Decreased earnings quarter-over-quarter at NSPI due to increased OM&G and higher depreciation expense. Increased earnings year-over-year due to investment tax credits related to clean technology investments and increased sales volumes driven by favourable weather, partially offset by higher OM&G and higher depreciation expense | (11) | 30 | ||||||
| Corporate | ||||||||
| Increased income tax recovery due to decreased deferred income tax asset valuation allowance and increased loss before provision for income taxes | 11 | 18 | ||||||
| Increased interest expense primarily due to increased total debt, partially offset by lower interest rates | (3) | (10) | ||||||
| Increased OM&G quarter-over-quarter and decreased year-over-year primarily due to timing of the recognition on long term compensation expense and related hedges | (16) | 8 | ||||||
| Other Variances | 1 | - | ||||||
| Adjusted net income – 2025 1,2 |
$ | 263 | $ | 878 | ||||
5
1 See “Non-GAAP Financial Measures and Ratios” noted below and “Segment Results and Non-GAAP Reconciliation” for reconciliation to nearest GAAP measure.
2 Excludes the charges related to the pending sale of NMGC, after-tax, gain on sale of LIL, after-tax, and the effect of after-tax MTM adjustments.
1 Non-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 Q3 2025 MD&A, which is incorporated herein by reference and can be found on SEDAR+ at www.sedarplus.ca. Reconciliation to the nearest GAAP measure is included in “Segment Results and Non-GAAP Reconciliation” above.
Forward-Looking Information
This news release contains forward-looking information or forward-looking statements within the meaning of applicable securities laws (collectively, “forward-looking information”), including without limitation, statements about the Company’s expectations regarding future growth, including the extension of its 7% to 8% rate base growth guidance through 2030, the nature and timing of its $20 billion capital and funding plan and its expectations that 80% of the capital plan will be invested in Florida, its expectations for 8% to 9% rate base growth for its Florida utilities, its plans to allocate more than 90% of its capital investments to reliability, grid modernization, renewable asset integration and technological innovation, and its intention to focus 55% of capital investments on strengthening transmission, distribution and gas infrastructure systems to support reliability and customer growth. 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. Additional detailed information about these assumptions, risks and uncertainties is included in Emera’s securities regulatory filings, including under the heading “Business Risks and Risk Management” in Emera’s annual Management’s Discussion and Analysis, and under the heading “Principal Risks and Uncertainties” in the notes to Emera’s annual and interim financial statements, which can be found on SEDAR+ at www.sedarplus.ca or on EDGAR at www.sec.gov. The forward-looking information in this news release is made only as of the
6
date of thereof, and Emera disclaims any intention or obligation to update or revise any forward-looking information.
Teleconference Call
The company will be hosting a teleconference today, Friday, November 7, at 9:30 a.m. Atlantic (8:30 a.m. Eastern) to discuss the Q3 2025 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.
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 2.6 million customers in Canada, the United States and the Caribbean. Our team of 7,600 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, VP, Investor Relations & Pensions 902-233-2674
dave.bezanson@emera.com
Media
media@emera.com
7
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 September 30, 2025.
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 July 1, 2025 and ended on September 30, 2025 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.
| Date: November 7, 2025 |
| “Scott Balfour”
|
| Scott Balfour |
| President and Chief Executive Officer |
Exhibit 99.6
FORM 52-109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE
I, Greg Blunden, 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 September 30, 2025.
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 July 1, 2025 and ended on September 30, 2025 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.
| Date: November 7, 2025 |
| “Greg Blunden”
|
| Greg Blunden |
| Chief Financial Officer |