Emera Inc 6-K, filed Aug 10, 2026
Emera Inc (EMA)
About this 6-K
Emera Inc filed this 6-K on August 10, 2026.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 6-K
REPORT OF FOREIGN PRIVATE ISSUER
PURSUANT TO RULE 13a-16 OR 15d-16
UNDER THE SECURITIES EXCHANGE ACT OF 1934
For the month of August 2026
Commission File Number: 001-42631
Emera Incorporated
(Exact name of registrant as specified in its charter)
5151 Terminal Road
Halifax NS B3J 1A1
Canada
(Address of principal executive offices)
Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.
Form 20-F ☐ Form 40-F ☒
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ☐
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ☐
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: August 7, 2026 | By: | /s/ Brian Curry
| ||||
| Name: Brian Curry Title: Corporate Secretary | ||||||
EXHIBIT INDEX
Exhibit 99.1
Management’s Discussion & Analysis
As at August 7, 2026
Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its consolidated subsidiaries and investments (collectively referred to as “Emera” or the “Company”) during the second quarter of, and year-to-date, 2026 relative to the same periods in 2025; and its financial position as at June 30, 2026 relative to December 31, 2025. The Company’s activities are carried out through five reportable segments: Florida Electric Utility, Canadian Electric Utilities, Gas Utilities and Infrastructure, Other Electric Utilities, and Other.
This MD&A should be read in conjunction with the Emera unaudited condensed consolidated interim financial statements and supporting notes as at and for the three and six months ended June 30, 2026; and the Emera annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2025. Emera follows United States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”). Additional information related to Emera, including the Company’s Annual Information Form, can be found on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov.
The accounting policies used by Emera’s rate-regulated entities may differ from those used by Emera’s non-rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities, revenues and expenses. At June 30, 2026, Emera’s rate-regulated subsidiaries and investments include:
| Rate-Regulated Subsidiary or Equity Investment |
Accounting Policies Approved/Examined By | |
|
Subsidiary |
||
| Tampa Electric Company (“TEC”) |
Florida Public Service Commission (“FPSC”) and the Federal Energy Regulatory Commission (“FERC”) | |
| Nova Scotia Power Inc. (“NSPI”) |
Nova Scotia Energy Board (“NSEB”) | |
| Peoples Gas System, Inc. (“PGS”) |
FPSC | |
| New Mexico Gas Company, Inc. (“NMGC”) |
New Mexico Public Regulation Commission (“NMPRC”) | |
|
SeaCoast Gas Transmission, LLC (“SeaCoast”) |
FPSC | |
| Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”) |
Canadian Energy Regulator (“CER”) | |
|
Barbados Light & Power Company Limited (“BLPC”) |
Fair Trading Commission, Barbados (“FTC”) | |
|
Equity Investments |
||
| NSP Maritime Link Inc. (“NSPML”) |
NSEB | |
|
Maritimes & Northeast Pipeline Limited Partnership and Maritimes & Northeast Pipeline, LLC (“M&NP”) |
CER and FERC | |
| St. Lucia Electricity Services Limited (“Lucelec”) |
National Utility Regulatory Commission | |
|
Wasoqonatl Transmission Incorporated (“WTI”) |
NSEB |
On May 12, 2026, Emera completed the sale of Grand Bahama Power Company Limited (“GBPC”). For further details, refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.
All amounts are in Canadian dollars (“CAD”), except for the Florida Electric Utility, Gas Utilities and Infrastructure, and Other Electric Utilities sections of the MD&A, which are reported in United States dollars (“USD”) unless otherwise stated.
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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 |
9 | |
| Business Overview and Outlook |
12 | |
| Florida Electric Utility |
12 | |
| Canadian Electric Utilities |
12 | |
| Gas Utilities and Infrastructure |
13 | |
| Other Electric Utilities |
13 | |
| Other |
14 | |
| Consolidated Balance Sheet Highlights |
15 | |
| Other Developments |
16 | |
| Financial Highlights |
17 | |
| Florida Electric Utility |
17 | |
| Canadian Electric Utilities |
18 |
| Gas Utilities and Infrastructure |
19 | |
| Other Electric Utilities |
20 | |
| Other |
21 | |
| Liquidity and Capital Resources |
23 | |
| Consolidated Cash Flow Highlights |
24 | |
| Contractual Obligations |
25 | |
| Debt Management |
26 | |
| Credit Ratings |
28 | |
| Guarantees and Letters of Credit |
28 | |
| Outstanding Stock Data |
29 | |
| Transactions with Related Parties |
29 | |
| Risk Management and Financial Instruments |
30 | |
| Disclosure and Internal Controls |
31 | |
| Critical Accounting Estimates |
32 | |
| Changes in Accounting Policies and Practices |
32 | |
| Future Accounting Pronouncements |
32 | |
| Summary of Quarterly Results |
33 |
FORWARD-LOOKING INFORMATION
This MD&A contains “forward-looking information” within the meaning of applicable Canadian securities laws and “forward-looking statements” within the meaning of applicable US securities laws, including without limitation, the United States Private Securities Litigation Reform Act of 1995 (collectively, “FLI”), which reflect the current view with respect to the Company’s expectations regarding future growth, results of operations, performance, earnings, capital investment, sales volumes, recovery of costs, timing of regulatory decisions, the expected timing and outcome of the pending sale of NMGC, the expected impact of the Cybersecurity Incident (as defined herein) on the Company’s financial position and results of operations, information technology (“IT”) systems restoration, insurance recoveries, and business continuity processes as well as other matters relating to the Cybersecurity Incident, business prospects and opportunities, and may not be appropriate for other purposes. All such information and statements are made pursuant to safe harbour provisions contained in applicable securities legislation. The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecast”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “targets”, “will”, “would” and similar expressions are often intended to identify FLI, although not all FLI contains these identifying words. The FLI reflects management’s current beliefs and is based on information currently available to Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the time at which, such events, performance or results will be achieved.
2
FLI is based on reasonable assumptions and is subject to risks, uncertainties, and other factors that could cause actual results to differ materially from historical results or results anticipated by the FLI. Factors that could cause results or events to differ from current expectations include, without limitation: regulatory and political risk; change in law risk; system operating and maintenance risks; uninsured risk; changes in economic conditions; commodity price and availability risk; liquidity and capital markets risk; general economic risk; changes in credit ratings; future dividend growth, rate base growth, and adjusted earnings per common share (“EPS”) growth; timing and costs associated with certain capital investments; expected impacts on Emera from challenges in the global economy; potential impacts of trade disputes and tariffs; estimated energy consumption rates; maintenance of adequate insurance coverage and receipt of proceeds; changes in customer energy usage patterns; developments in technology that could impact demand for electricity; climate risk; weather risk, including higher frequency and severity of weather events; risk of wildfires; unanticipated maintenance and other expenditures; derivative financial instruments and hedging; interest rate risk; inflation risk; counterparty risk; disruption of fuel supply; supply chain risk; environmental risks; foreign exchange (“FX”); regulatory and government decisions, including changes to environmental legislation, financial reporting and tax legislation; risks associated with future employee benefit plan performance and funding requirements; loss of service area; risks and costs associated with failure of IT infrastructure and cybersecurity incidents including IT systems restoration and business continuity processes; uncertainties associated with infectious diseases, pandemics and similar public health threats; risks associated with health and safety; project development and land use rights risk; market energy sales prices; labour relations; and availability of labour and management resources.
Readers are cautioned not to place undue reliance on FLI, as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the FLI. All FLI in this MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, Emera undertakes no obligation and disclaims any intention to revise or update any FLI as a result of new information, future events or otherwise. Additional detailed information about the above referenced assumptions, risks, uncertainties and other factors is included in Emera’s securities regulatory filings, which can be found on SEDAR+ at www.sedarplus.ca or on EDGAR at www.sec.gov.
INTRODUCTION AND STRATEGIC OVERVIEW
Emera (TSX/NYSE: EMA) is a North American provider of energy services, owning and operating a portfolio of cost-of-service, rate-regulated electric and gas utilities. Its largest operations are in Florida, with additional operations in Atlantic Canada, New Mexico, and the Caribbean. Emera is headquartered in Halifax, Nova Scotia, Canada.
Emera’s business strategy is centred on continued investment in its regulated utilities, combined with a focus on operational excellence and efficiency, to safely and reliably deliver energy to its 2.7 million customers. Effective execution of these priorities supports predictable and growing earnings, cash flow, and dividends for shareholders.
Earnings opportunities in regulated utilities are a function of the magnitude of net investment in the utility (known as “rate base”), the amount of equity in the capital structure, and the targeted return on that equity (“ROE”), all as established and approved through regulation. Earnings are also affected by sales volumes and operating expenses. In 2025, Emera’s regulated cost-of-service utilities in Florida accounted for 67 per cent of average consolidated rate base, with Atlantic Canada comprising 25 per cent, and the Caribbean and New Mexico 4 per cent each.
Emera’s capital investment plan is forecasted to be approximately $20 billion from 2026 through 2030 and is focused on delivering value for customers through prudent investments in reliability and system resiliency, infrastructure modernization, expansion to address customer growth, integration of renewables, and technological innovations to deliver better customer experiences. It is anticipated that approximately 80 per cent of this capital investment will be made in Emera’s Florida utilities, necessitated by customer growth and system requirements at both TEC and PGS.
3
| millions of dollars |
2026 | 2027 | 2028 | 2029 | 2030 | Total | ||||||||||||||||||
| Capital investment plan (1)(2) |
$ | 4,020 | $ | 3,730 | $ | 4,140 | $ | 4,180 | $ | 4,330 | $ | 20,400 | ||||||||||||
| Average consolidated rate base forecast (1)(2): |
||||||||||||||||||||||||
| US operations |
$ | 23,180 | $ | 25,100 | $ | 27,140 | $ | 29,300 | $ | 31,480 | ||||||||||||||
| Canadian operations |
7,340 | 7,660 | 7,990 | 8,320 | 8,580 | |||||||||||||||||||
| Total |
$ | 30,520 | $ | 32,760 | $ | 35,130 | $ | 37,620 | $ | 40,060 |
(1) Capital investment plan and average consolidated rate base forecast are updated annually, typically in the second half of the year.
(2) The table above excludes NMGC. For more information on the pending sale of NMGC, refer to the “Other Developments” section.
Emera’s capital investment plan will be funded primarily through internally generated cash flows, debt raised at the operating company level consistent with regulated capital structures, equity issuances, and proceeds from the pending close of the NMGC transaction. Generally, Emera’s equity requirements are expected to be funded through the issuance of hybrid securities, and the issuance of common equity through Emera’s dividend reinvestment plan (“DRIP”) and its at-the-market program (“ATM program”). Maintaining investment-grade credit ratings is a core strategic priority of the Company.
Emera has increased dividends per common share paid for 19 consecutive years and has provided annual dividend growth guidance of one to two per cent. Emera anticipates average adjusted EPS growth of five to seven per cent through 2030, using 2024 as the base year, which will support continued reduction in the ratio of dividend payout to adjusted net income over time. For further information on the non-GAAP ratios “Adjusted EPS” and “Dividend Payout Ratio of Adjusted Net Income”, refer to the “Non-GAAP Financial Measures and Ratios” section.
NON-GAAP FINANCIAL MEASURES AND RATIOS
Emera uses financial measures and ratios that do not have standardized meaning under USGAAP and are calculated by adjusting certain GAAP measures for specific items. They may not be comparable to similar measures presented by other entities. These measures and ratios are discussed and reconciled below.
Adjusted Net Income, Adjusted EPS – Basic and Dividend Payout Ratio of Adjusted Net Income
Emera calculates an adjusted net income attributable to common shareholders (“adjusted net income”) measure by excluding the items below from net income attributable to common shareholders. Management believes excluding these items better distinguishes ongoing operations of the business and allows investors to better understand and evaluate the business.
All periods: Mark-to-Market (“MTM”) Adjustments
Management believes excluding from net income the effect of MTM valuations and changes thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows, and therefore excludes MTM adjustments for evaluation of performance and incentive compensation. The MTM adjustments are related to the following:
| • | held-for-trading (“HFT”) commodity derivative instruments, including adjustments related to the price differential between the point where natural gas is sourced and where it is delivered, and the related amortization of transportation capacity recognized as a result of certain Emera Energy marketing and trading transactions; |
| • | the business activities of Bear Swamp Power Company LLC (“Bear Swamp”) included in Emera’s equity income; |
| • | equity securities held in BLPC; and |
| • | FX hedges entered into to hedge USD denominated operating unit earnings exposure. |
4
2026: Loss on Sale of GBPC
In Q2 2026, Emera recognized a $19 million loss, after tax and transaction costs, on the sale of GBPC. For further details, refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.
2025: Charges related to the Pending Sale of NMGC
On August 5, 2025, Emera entered into an agreement to sell NMGC. In Q2 2025, the Company recognized a $71 million non-cash impairment charge, after-tax, and an additional loss of $1 million in estimated transaction costs, after-tax, related to the pending sale. For further details, refer to the “Significant Items Affecting Earnings” section.
Emera calculates adjusted net income for the Other Electric Utilities and Other segments. Reconciliation to the nearest GAAP measure is included in each segment. For more information, refer to the Financial Highlights section for each of Other Electric Utilities, and Other.
Adjusted EPS – basic and dividend payout ratio of adjusted net income are non-GAAP ratios which are calculated using adjusted net income, as described above. For further details on dividend payout ratio of adjusted net income, see the “Dividend Payout Ratio” section in the Company’s 2025 annual MD&A.
Reconciliation of Net Income Attributable to Common Shareholders to Adjusted Net Income
| For the | Three months ended June 30 |
Six months ended June 30 |
||||||||||||||
| millions of dollars (except per share amounts) | 2026 | 2025 | 2026 | 2025 | ||||||||||||
| Net income attributable to common shareholders |
$ | 105 | $ | 135 | $ | 667 | $ | 718 | ||||||||
| Less: |
||||||||||||||||
| MTM (loss) gain, after-tax (1) |
(88) | (29) | 59 | 175 | ||||||||||||
| Loss on sale of GBPC, after tax and transaction costs (2) |
(19) | - | (19) | - | ||||||||||||
| Charges related to the pending sale of NMGC, after-tax (3) |
- | (72) | - | (72) | ||||||||||||
| Adjusted net income |
$ | 212 | $ | 236 | $ | 627 | $ | 615 | ||||||||
| EPS – basic |
$ | 0.34 | $ | 0.45 | $ | 2.19 | $ | 2.41 | ||||||||
| Adjusted EPS – basic |
$ | 0.69 | $ | 0.79 | $ | 2.06 | $ | 2.07 | ||||||||
(1) Net of income tax recovery of $37 million for the three months ended June 30, 2026 (2025 – $13 million recovery) and $24 million income tax expense for the six months ended June 30, 2026 (2025 – $71 million expense).
(2) Net of income tax recovery of $2 million for the three and six months ended June 30, 2026.
(3) Represents a $71 million non-cash impairment charge, after-tax, and $1 million in transaction costs, after-tax for the three and six months ended June 30, 2025. Amounts are net of an income tax recovery of $5 million for the three and six months ended June 30, 2025.
5
EBITDA and Adjusted EBITDA
Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) and adjusted EBITDA are non-GAAP financial measures used by Emera. These financial measures are used by numerous investors and lenders to better understand cash flows and credit quality. EBITDA is useful to assess Emera’s operating performance and indicates the Company’s ability to service or incur debt, invest in capital, and finance working capital requirements. Adjusted EBITDA represents EBITDA absent the income effect of MTM adjustments, loss on sale of GBPC, and 2025 charges related to the pending sale of NMGC.
Reconciliation of Net Income to EBITDA and Adjusted EBITDA
| For the | Three months ended June 30 |
Six months ended June 30 |
||||||||||||||
| millions of dollars | 2026 | 2025 | 2026 | 2025 | ||||||||||||
| Net income (1) |
$ | 124 | $ | 154 | $ | 706 | $ | 755 | ||||||||
| Interest expense, net |
275 | 249 | 546 | 504 | ||||||||||||
| Income tax (recovery) expense |
(25) | (9) | 104 | 110 | ||||||||||||
| Depreciation and amortization |
336 | 316 | 675 | 635 | ||||||||||||
| EBITDA |
$ | 710 | $ | 710 | $ | 2,031 | $ | 2,004 | ||||||||
| Less: MTM (loss) gain, excluding income tax |
(125) | (42) | 83 | 246 | ||||||||||||
| Loss on sale of GBPC, excluding income tax |
(21) | - | (21) | - | ||||||||||||
| Charges related to the pending sale of NMGC, excluding income tax |
- | (77) | - | (77) | ||||||||||||
| Adjusted EBITDA |
$ | 856 | $ | 829 | $ | 1,969 | $ | 1,835 | ||||||||
| (1) Net income is before Preferred stock dividends. |
| |||||||||||||||
CONSOLIDATED FINANCIAL REVIEW
Significant Items Affecting Earnings
2026:
Earnings Impact of MTM (Loss) Gain, After-Tax
MTM loss, after-tax, increased $59 million to $88 million in Q2 2026 compared to $29 million in Q2 2025. Year-to-date, MTM gain, after-tax, decreased $116 million to $59 million in 2026 compared to $175 million for the same period in 2025. These unfavourable changes in MTM, after-tax, were primarily due to a loss on Corporate FX hedges compared to a gain in prior year and amortization of gas transportation assets and changes in existing positions at Emera Energy Services (“EES”).
Loss on Sale of GBPC
On May 12, 2026, Emera completed the sale of GBPC. A loss on sale of $21 million after transaction costs ($19 million, after tax and transaction costs, or $0.06 per common share) was recorded. This was recorded in “Other (expense) income, net” on the Condensed Consolidated Statements of Income and included in the “Other Electric Utilities” and “Other” segments.
As a result of the sale, earnings contributions from GBPC were $7 million lower in Q2 2026 and year-to-date 2026 compared to the same periods in 2025.
6
2025:
Charges Related to the Pending Sale of NMGC
In Q2 2025, Emera recognized a non-cash impairment charge of $75 million ($71 million after-tax, or $0.24 per common share) related to the remeasurement of the NMGC disposal group to fair value (“FV”) less costs to sell. This was recorded in “Impairment charge” on the Condensed Consolidated Statements of Income and included in the Other segment. For further details on the pending sale of NMGC, refer to the “Other Developments” section. For further details on the non-cash impairment charge, refer to note 3 in the unaudited condensed consolidated interim financial statements.
Consolidated Financial Highlights
| For the millions of dollars |
Three months ended June 30 |
Six months ended June 30 |
||||||||||||||
| Adjusted Net Income | 2026 | 2025 | 2026 | 2025 | ||||||||||||
| Florida Electric Utility |
$ | 261 | $ | 260 | $ | 441 | $ | 424 | ||||||||
| Canadian Electric Utilities |
16 | 17 | 102 | 138 | ||||||||||||
| Gas Utilities and Infrastructure |
55 | 48 | 191 | 168 | ||||||||||||
| Other Electric Utilities |
5 | 12 | 13 | 12 | ||||||||||||
| Other |
(125) | (101) | (120) | (127) | ||||||||||||
| Adjusted net income |
$ | 212 | $ | 236 | $ | 627 | $ | 615 | ||||||||
| MTM (loss) gain, after-tax |
(88) | (29) | 59 | 175 | ||||||||||||
| Loss on sale of GBPC, after tax and transaction costs |
(19) | - | (19) | - | ||||||||||||
| Charges related to the pending sale of NMGC, after-tax |
- | (72) | - | (72) | ||||||||||||
| Net income attributable to common shareholders |
$ | 105 | $ | 135 | $ | 667 | $ | 718 | ||||||||
7
The following table highlights significant quarter-over-quarter and year-over-year changes in adjusted net income from 2025 to 2026:
| For the | Three months ended | Six months ended | ||||||
| millions of dollars | June 30 | June 30 | ||||||
| Adjusted net income – 2025 |
$ | 236 | $ | 615 | ||||
| Operating Unit Performance |
||||||||
| Increased earnings at PGS due to higher revenue from new base rates and higher off-system sales, partially offset by higher operating, maintenance and general expenses (“OM&G”) and depreciation | 15 | 33 | ||||||
| Increased equity earnings at Bear Swamp due to business interruption insurance received related to an unplanned outage in 2025 and higher generation | 19 | 23 | ||||||
| Increased earnings year-over-year at TEC due to higher revenue from new base rates and higher off-system sales, partially offset by higher depreciation, increased state and municipal taxes, higher interest expense and the impact of a stronger CAD | 1 | 17 | ||||||
| Decreased earnings year-over-year at NSPI due to lower income tax recovery as a result of higher clean technology investment tax credits in 2025 ($18 million), higher OM&G and higher depreciation expense. These were partially offset by higher sales volumes | - | (36) | ||||||
| Decreased earnings due to the sale of GBPC in May 2026 | (7) | (7) | ||||||
| Decreased earnings quarter-over-quarter at EES due to timing of hedge settlements related to storage positions and higher transport costs. Increased earnings year-over year due to favourable market conditions that led to higher natural gas prices and increased volatility that created profitable opportunities | (10) | 26 | ||||||
| Decreased earnings at NMGC primarily due to higher OM&G | (12) | (12) | ||||||
| Corporate | ||||||||
| Increased income tax recovery quarter-over-quarter primarily due to an increased loss before provision for income taxes, partially offset by an unfavourable deferred income tax asset valuation adjustment. Increased income tax recovery year-over-year due to an increased loss before provision for income taxes | 3 | 9 | ||||||
| Increase OM&G, pre-tax, primarily due to lower gain on the long-term incentive hedge and increased costs as a result of New York Stock Exchange (“NYSE”) listing | (1) | (13) | ||||||
| Increased Corporate FX losses on the translation of USD short-term debt balances. Year-over-year is partially offset by a decreased realized loss on FX hedges | (9) | (4) | ||||||
| Increased interest expense, pre-tax, due to higher long-term debt resulting from the timing of financings, partially offset by interest earned on debt proceeds held in invested cash. Year-over-over is also partially offset by lower short-term debt | (21) | (28) | ||||||
| Other Variances |
(2) | 4 | ||||||
| Adjusted net income – 2026 |
$ | 212 | $ | 627 | ||||
For further details of contributions by reportable segments, refer to the “Financial Highlights” section.
8
| For the | Six months ended June 30 | |||||||
| millions of dollars | 2026 | 2025 | ||||||
| Operating cash flow before changes in working capital |
$ | 1,411 | $ | 1,306 | ||||
| Changes in working capital |
(9) | (507) | ||||||
| Operating cash flow |
$ | 1,402 | $ | 799 | ||||
| Investing cash flow |
$ | (1,531) | $ | (1,672) | ||||
| Financing cash flow |
$ | 95 | $ | 877 | ||||
For further discussion of cash flow, refer to the “Consolidated Cash Flow Highlights” section.
| $ | $ | |||||||
| As at |
June 30 | December 31 | ||||||
| millions of dollars |
2026 | 2025 | ||||||
| Total assets |
$ | 46,556 | $ | 44,817 | ||||
| Total long-term debt (including current portion) (1) |
$ | 19,587 | $ | 19,654 | ||||
| (1) Excludes NMGC balances classified as held for sale. For further details refer to the “Other Developments” section and note 3 in the unaudited condensed consolidated interim financial statements. |
| |||||||
Consolidated Income Statement Highlights
| $ | $ | $ | $ | $ | $ | |||||||||||||||||||
| For the | Three months ended | Six months ended | ||||||||||||||||||||||
| millions of dollars | June 30 | June 30 | ||||||||||||||||||||||
| (except per share amounts) | 2026 | 2025 | Variance | 2026 | 2025 | Variance | ||||||||||||||||||
| Operating revenues |
$ | 2,011 | $ | 1,988 | $ | 23 | $ | 4,824 | $ | 4,664 | $ | 160 | ||||||||||||
| Operating expenses |
1,657 | 1,693 | 36 | 3,527 | 3,444 | (83) | ||||||||||||||||||
| Income from operations |
$ | 354 | $ | 295 | $ | 59 | $ | 1,297 | $ | 1,220 | $ | 77 | ||||||||||||
| Other (expense) income, net |
$ | (12) | $ | 85 | $ | (97) | $ | 6 | $ | 116 | $ | (110) | ||||||||||||
| Income tax (recovery) expense |
$ | (25) | $ | (9) | $ | 16 | $ | 104 | $ | 110 | $ | 6 | ||||||||||||
| Net income attributable to common shareholders |
$ | 105 | $ | 135 | $ | (30) | $ | 667 | $ | 718 | $ | (51) | ||||||||||||
| Adjusted net income |
$ | 212 | $ | 236 | $ | (24) | $ | 627 | $ | 615 | $ | 12 | ||||||||||||
| Weighted average shares of common stock outstanding (in millions) |
306.4 | 298.6 | 7.8 | 304.9 | 297.8 | 7.1 | ||||||||||||||||||
| EPS – basic |
$ | 0.34 | $ | 0.45 | $ | (0.11) | $ | 2.19 | $ | 2.41 | $ | (0.22) | ||||||||||||
| EPS – diluted |
$ | 0.34 | $ | 0.45 | $ | (0.11) | $ | 2.18 | $ | 2.41 | $ | (0.23) | ||||||||||||
| Adjusted EPS – basic |
$ | 0.69 | $ | 0.79 | $ | (0.10) | $ | 2.06 | $ | 2.07 | $ | (0.01) | ||||||||||||
| Dividends per common share declared |
$ | 0.7325 | $ | 0.7250 | $ | 0.0075 | $ | 1.4650 | $ | 1.4500 | $ | 0.0150 | ||||||||||||
| Adjusted EBITDA |
$ | 856 | $ | 829 | $ | 27 | $ | 1,969 | $ | 1,835 | $ | 134 | ||||||||||||
Operating Revenues
For Q2 2026, operating revenues increased $23 million compared to Q2 2025 and, excluding the change in MTM impacts, increased $44 million. The increase was due to new base rates at TEC and PGS; higher fuel cost recoveries at BLPC; and increased commercial and industrial sales volumes at NSPI. These were partially offset by decreased revenues due to the sale of GBPC.
Year-to-date 2026, operating revenues increased $160 million compared to 2025 and, excluding the change in MTM impacts, increased $247 million. The increase was due to higher marketing and trading margin at EES; new base rates at TEC and PGS; increased off-system sales at TEC and PGS; higher storm cost recovery revenue at TEC (offset in OM&G); and increased commercial and industrial sales volumes at NSPI. These were partially offset by the impact of a stronger CAD; lower fuel cost recoveries at NMGC; and decreased revenues due to the sale of GBPC.
9
Operating Expenses
For Q2 2026, operating expenses decreased $36 million compared to Q2 2025 and, excluding charges related to the pending sale of NMGC of $75 million in 2025, increased $39 million. Year-to-date operating expenses increased $83 million compared to 2025, and excluding charges related to the pending sale of NMGC in 2025, increased $158 million. These increases were due to increased OM&G due to higher labour and benefits at NMGC and PGS; and increased depreciation expense at TEC, PGS and NSPI. Year-over-year increase was also due to higher natural gas prices at TEC and PGS; higher storm costs recognition at TEC (offset in revenue); higher OM&G at Corporate and NSPI, partially offset by the impact of a stronger CAD; and lower natural gas prices at NMGC.
Other (Expense) Income, net
Other income, net decreased $97 million in Q2 2026, compared to the same period in Q2 2025. Year-to-date, other income, net decreased $110 million compared to the same period in 2025. The changes were due to lower unrealized FX gains at Corporate and the loss on sale of GBPC.
Income Tax (Recovery) Expense
For Q2 2026, income tax recovery increased $16 million compared to Q2 2025 due to decreased earnings before provision for income taxes and the tax impact of charges related to the pending sale of NMGC in 2025.
Year-to-date 2026, income tax expense decreased $6 million compared to 2025 due to decreased earnings before provision for income taxes, the tax impact of charges related to the pending sale of NMGC in 2025 and increased tax credits recognized at TEC. This was partially offset by decreased tax credits recognized at NSPI and an unfavourable impact of foreign currency translation.
Net Income and Adjusted Net Income
For Q2 2026, net income attributable to common shareholders, compared to Q2 2025, was unfavourably impacted by the $59 million increase in MTM losses, after-tax, and the $19 million loss on sale of GBPC, after tax and transaction costs, and favourably impacted by the $72 million charges related to the pending sale of NMGC recognized in Q2 2025. Excluding these impacts, adjusted net income decreased $24 million, primarily due to increased interest expense and FX losses on the translation of USD short-term debt balances at Corporate; decreased earnings at NMGC and EES; and lower earnings due to the sale of GBPC. These were partially offset by increased earnings at PGS; and higher equity earnings at Bear Swamp.
Year-to-date 2026, net income attributable to common shareholders, compared to the same period in 2025, was favourably impacted by the $72 million charges related to the pending sale of NMGC recognized in Q2 2025, and unfavourably impacted by the $116 million decrease in MTM gain, after-tax, and the $19 million loss on sale of GBPC. Excluding these changes, adjusted net income increased $12 million. The increase was primarily due to increased earnings at PGS, EES and TEC; higher equity earnings at Bear Swamp and higher income tax recovery at Corporate. These were partially offset by increased interest expense and higher OM&G at Corporate; lower earnings at NSPI and NMGC; and lower earnings due to the sale of GBPC.
EPS – Basic and Adjusted EPS – Basic
For Q2 2026, EPS – basic and adjusted EPS were lower due to the impact of lower earnings and increased weighted average shares outstanding.
Year-over-year, EPS – basic was lower due to the impact of lower earnings and increased weighted average shares outstanding. Adjusted EPS year-over-year was consistent with 2025.
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Effect of Foreign Currency Translation
Results of foreign operations are translated at the weighted average rate of exchange, and assets and liabilities of foreign operations are translated at period end rates. For additional details on the effects of foreign currency translation, refer to the Company’s 2025 annual MD&A.
The relevant CAD/USD exchange rates for 2026 and 2025 are as follows:
| Three months ended June 30 |
Six months ended June 30 |
Year ended December 31 |
||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | 2025 | ||||||||||||||||
| Weighted average CAD/USD |
$ | 1.38 | $ | 1.40 | $ | 1.37 | $ | 1.43 | $ | 1.41 | ||||||||||
| Period end CAD/USD exchange rate |
$ | 1.42 | $ | 1.36 | $ | 1.42 | $ | 1.36 | $ | 1.37 | ||||||||||
The table below includes Emera’s significant segments whose contributions to adjusted net income are recorded in USD currency:
| Three months ended | Six months ended | |||||||||||||||
| For the | June 30 | June 30 | ||||||||||||||
| millions of USD | 2026 | 2025 | 2026 | 2025 | ||||||||||||
| Florida Electric Utility |
$ | 189 | $ | 188 | $ | 320 | $ | 302 | ||||||||
| Gas Utilities and Infrastructure (1) |
33 | 31 | 128 | 110 | ||||||||||||
| Other Electric Utilities (2) |
3 | 9 | 10 | 9 | ||||||||||||
| Other segment (3) |
(55) | (55) | (30) | (50) | ||||||||||||
| Total (4) |
$ | 170 | $ | 173 | $ | 428 | $ | 371 | ||||||||
| (1) Includes USD net income from PGS, NMGC, SeaCoast and M&NP. |
| |||||||||||||||
| (2) Excludes $12 million USD, after-tax loss on sale of GBPC for the three and six months ended June 30, 2026. |
| |||||||||||||||
| (3) Includes Emera Energy’s USD adjusted net income from EES, Bear Swamp and interest expense on Emera Inc.’s USD denominated debt. |
| |||||||||||||||
| (4) Excludes $52 million USD MTM loss, after-tax, for the three months ended June 30, 2026 (2025 – $45 million USD MTM loss, after-tax) and $58 million USD MTM gain, after-tax, for the six months ended June 30, 2026 (2025 – $98 million USD MTM gain, after-tax). |
| |||||||||||||||
Strengthening of the CAD decreased net income attributable to common shareholders by $13 million in Q2 2026 and $43 million year-to-date compared to the same periods in 2025. In Q2 2026, the impact of the change in FX rates on adjusted net income was nil. Year-to-date, strengthening of the CAD decreased adjusted net income by $17 million, compared to the same period in 2025. These impacts include the effect of the FX hedges used to mitigate translation risk of USD earnings, which are included in Corporate in the Other segment.
11
BUSINESS OVERVIEW AND OUTLOOK
There have been no material changes in Emera’s business overview and outlook from the Company’s 2025 annual MD&A, except for the updates disclosed below.
Florida Electric Utility
TEC anticipates earning within its allowed ROE range in 2026. USD earnings are expected to be higher in 2026 than 2025 as a result of new base rates effective January 1, 2026, and continued customer growth.
On April 6, 2026, the FPSC established a docket for further study of certain purchased power costs recovered through the fuel adjustment clause. On April 15, 2026, TEC filed a petition with the FPSC seeking approval of revised depreciation rates for Bayside Station assets, which would decrease annual depreciation expense by approximately $20 million USD. On June 16, 2026, TEC and the Office of Public Counsel filed with the FPSC a motion to approve a settlement agreement for the revised depreciation rates to be effective on July 1, 2026. As part of the settlement agreement, TEC agreed to a decrease fuel clause recovery by $10 million USD in 2026, which will be reflected on customer’s bills in 2027. TEC also agreed to not seek approval for an increase in base revenues effective prior to January 1, 2028, except for previously approved subsequent year adjustments from the 2024 rate case and large load customer tariffs required by statute. On August 4, 2026, the FPSC approved the settlement agreement.
On February 3, 2025, the FPSC issued the final order approving the 2024 rate case decision, effective January 1, 2025. In March 2025, two intervening parties each filed a notice of appeal to the Florida Supreme Court regarding the outcome of TEC’s 2024 base rate proceeding. On January 12, 2026, the intervening parties filed their briefs related to the appeal. On April 13, 2026, the FPSC and TEC filed responses to the briefs. To date, the Florida Supreme Court has not made a decision regarding this case.
In 2026, capital investment in the Florida Electric Utility segment is expected to be $1.8 billion USD (2025 – $1.6 billion USD), including allowance for funds used during construction (“AFUDC”). Capital projects include investment in generation reliability projects, storm hardening, grid modernization, and transmission expansion.
Canadian Electric Utilities
NSPI
NSPI expects earnings in 2026 to be higher than 2025 as a result of new base rates effective May 1, 2026, as discussed below, but anticipates earning below its allowed ROE range in 2026 primarily due to a delay in the general rate application (“GRA”) decision. Sales volumes are expected to be higher in 2026 than in 2025.
On April 30, 2026, the NSEB approved the GRA with changes effective on May 1, 2026. This results in an average annual customer rate increase of 1.2 per cent, and a further average annual increase of 2.5 per cent on January 1, 2027. The approved rates are expected to result in annual revenue (fuel and non-fuel) increases of $31 million in 2026 and $97 million in 2027. Any under or over-recovery of fuel costs will be addressed through NSPI’s established fuel adjustment mechanism (“FAM”) process with the NSEB. NSPI’s ROE range will continue to be 8.75 per cent to 9.25 per cent, based on a common equity component of up to 40 per cent. The NSEB also approved the depreciation study completed in 2025 and continuation of the storm rider for each of 2026 and 2027. Additionally, the NSEB approved deferral of depreciation and financing costs for assets within the scope of NSPI’s Decarbonization Deferral Account as of December 31, 2025. NSPI has proposed to recover these costs through a rate reducing securitization transaction, the timing of which requires final support from the Province of Nova Scotia.
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In 2026, capital investment is expected to be approximately $700 million (2025 – $712 million), including AFUDC. NSPI is primarily investing in capital projects required to support power system reliability and reliable service for customers.
NSPML
Equity earnings from NSPML in 2026 are expected to be consistent with 2025. The NSPML investment is recorded as “Investments subject to significant influence” on Emera’s Consolidated Balance Sheets.
On June 25, 2026, NSPML submitted an application to the NSEB requesting recovery of $200 million in 2027 and $192 million in 2028 for costs associated with the Maritime Link. A decision is expected in Q4 2026.
On May 11, 2026, the NSEB issued its decision on NSPML’s 2026 assessment application, reducing NSPML’s approved regulated ROE from 9.0 per cent to 8.75 per cent and approved the collection of up to $198 million in Maritime Link costs for 2026, subject to a monthly holdback of up to $4 million if certain delivery requirements are not met. There was no holdback recorded year-to-date in 2026.
In 2026, capital investment at NSPML is expected to be approximately $40 million (2025 – $7 million).
Gas Utilities and Infrastructure
PGS
PGS anticipates earning within its allowed ROE range in 2026. USD earnings are expected to be higher in 2026 than 2025, as a result of new base rates effective January 1, 2026, favourable market conditions for off system sales revenue and continued customer growth.
In 2026, capital investment is expected to be approximately $445 million USD (2025 – $323 million USD), including AFUDC. PGS will make investments to maintain the reliability of their systems and support customer growth.
NMGC
On August 5, 2024, Emera announced an agreement to sell NMGC. As a result of the pending sale, NMGC’s assets and liabilities were classified as held for sale as of Q3 2024. On July 30, 2026, the NMPRC issued a final order approving the transaction, which is expected to close in August 2026. For more information on the pending transaction, refer to the “Other Developments” section.
NMGC’s USD earnings contribution to Emera in 2026 are expected to be lower than in 2025 as a result of the pending sale of NMGC and the resulting partial-year earnings contribution.
Other Electric Utilities
On May 12, 2026, Emera completed the sale of GBPC. For further details, refer to the “Other Developments” section.
Other Electric Utilities’ USD adjusted earnings in 2026 are expected to be lower than 2025 due to the sale of GBPC.
In November 2025, the Government of Barbados and BLPC agreed to new Transmission, Distribution, Sales and Dispatch (“T&D”) and Generation and Energy Storage (“G&S”) licenses. On May 11, 2026, BLPC’s new licenses became effective after the repeal of the previous license. The G&S license is valid until 2047, unless otherwise extended. The T&D License is valid for 30 years.
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In 2026, capital investment in the Other Electric Utilities segment is expected to be approximately $80 million USD (2025 – $67 million USD), including AFUDC, primarily in projects to support system reliability.
Other
The adjusted net loss from the Other segment is expected to be consistent with 2025. Higher contributions from EES, as discussed below, are expected to be offset by higher Corporate OM&G and interest expense.
Earnings from EES are generally dependent on market conditions. In particular, volatility in natural gas and electricity markets, which can be influenced by weather, local supply constraints and other supply and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1 and Q4 usually providing the greatest opportunity for earnings. EES is generally expected to deliver annual adjusted net income of $15 million USD to $30 million USD. However, in light of strong market conditions in Q1 2026, EES expects adjusted net income for 2026 to be $60 million USD to $80 million USD.
In 2026, capital investment in the Other segment is expected to be approximately $10 million (2025 – $6 million).
14
CONSOLIDATED BALANCE SHEET HIGHLIGHTS
Significant changes in the Consolidated Balance Sheets between December 31, 2025 and June 30, 2026 include:
| millions of dollars | Total Increase (Decrease) |
Explanation of Increase (Decrease) | ||||
| Assets | ||||||
| Derivative instruments (current and long-term) |
$ | 71 | Increased due to new contracts and changes in existing positions at EES, and higher balance on FX hedges at Corporate | |||
| Regulatory assets (current and long- term) |
(100) | Decreased due to lower storm costs recovery assets at TEC, and the sale of GBPC. These were partially offset by increased deferred income tax regulatory asset and deferrals related to the fuel adjustment mechanism (“FAM”) at NSPI, and the effect of FX translation of Emera’s non-Canadian affiliates | ||||
| Property, plant and equipment (“PP&E”), net of accumulated depreciation and amortization |
1,541 | Increased due to capital additions in excess of depreciation and the effect of FX translation of Emera’s non-Canadian affiliates, partially offset by the sale of GBPC | ||||
| Goodwill |
205 | Increased due to the effect of FX translation of Emera’s non-Canadian affiliates | ||||
| Liabilities and Equity | ||||||
| Short-term debt and long-term debt (including current portion) | $ | 656 | Increased due to issuance of long-term debt at Emera US Finance, LLC (“Emera Finance”) and PGS, higher utilization of committed credit facilities at Corporate, and the effect of FX translation of Emera’s non-Canadian affiliates. These were partially offset by repayment of long-term debt at Emera US Finance LP (“Emera US Finance”), and the sale of GBPC | |||
| Accounts payable | (258) | Decreased due to lower commodity prices at EES, timing of accounts payable at NSPI and the sale of GBPC. These were partially offset by timing of property taxes payable at TEC and the effect of FX translation of Emera’s non-Canadian affiliates | ||||
| Deferred income tax liabilities, net of deferred income tax assets | 169 | Increased due to tax deductions in excess of accounting depreciation related to PP&E, and the effect of FX translation of Emera’s non-Canadian affiliates. These were partially offset by a decrease in net regulatory assets, and increased tax credits at TEC | ||||
| Regulatory liabilities (current and long-term) | 75 | Increased due to the effect of FX translation of Emera’s non-Canadian affiliates, and higher storm reserve regulatory liability at TEC | ||||
| Other liabilities (current and long-term) |
105 | Increased due to timing of interest payments at Corporate, timing of sales tax payments at EES, and the effect of FX translation of Emera’s non-Canadian affiliates | ||||
| Common stock | 363 | Increased due to shares issued | ||||
| Accumulated other comprehensive income |
407 | Increased due to the effect of FX translation of Emera’s non-Canadian affiliates | ||||
| Retained earnings |
221 | Increased due to net income in excess of dividends paid | ||||
(1) On August 5, 2024, Emera announced the sale of NMGC. As a result, NMGC’s assets and liabilities were classified as held for sale beginning in Q3 2024. For further details, refer to the “Other Developments” section and note 3 in the unaudited condensed consolidated interim financial statements.
15
OTHER DEVELOPMENTS
Sale of GBPC
On May 12, 2026, Emera completed the sale of its 100 per cent interest in GBPC. As a result of the sale, Emera recognized a loss of $21 million after transaction costs ($19 million, after tax and transaction costs, or $0.06 per common share). This was recorded in “Other (expense) income, net” on the Condensed Consolidated Statements of Income and included in the “Other Electric Utilities” and “Other” segments.
Canadian Tax Legislation Changes
On March 26, 2026, Bill C-15, an Act to implement certain provisions of the 2025 budget tabled in Parliament on November 4, 2025, was enacted. Bill C-15, among other measures, reinstates the Accelerated Investment Incentive (“AII”) and introduces the Clean Electricity Investment Tax Credit (“CEITC”). The AII provides enhanced first-year capital cost allowance deductions, while the CEITC is a refundable tax credit of 15 per cent, which is reduced to 5 per cent if prescribed labour requirements are not met, on eligible property, including interprovincial and territorial transmission assets and qualifying refurbishments on eligible property. The enactment of Bill C-15 did not have a material impact on the Company year-to-date in 2026. The Company continues to assess potential future impacts of the legislation.
Pending Sale of NMGC
On August 5, 2024, Emera entered into an agreement to sell its indirect wholly-owned subsidiary NMGC for a total enterprise value of approximately $1.3 billion USD, consisting of cash proceeds and the transfer of debt and customary closing adjustments. On July 30, 2026, the NMPRC issued a final order approving the transaction. On July 31, 2026, certain of the intervening parties filed a notice of appeal of the final order to the New Mexico Supreme Court. There have been no further steps taken in the appeal process to date. The transaction is expected to close in August 2026.
As a result of the pending sale, NMGC’s assets and liabilities were classified as held for sale beginning Q3 2024 and the carrying value of the assets and liabilities were adjusted to FV less cost to sell. At each reporting date, the Company performs an assessment of the FV of the disposal group by comparing the FV of expected transaction proceeds, less costs to sell, to the carrying value of net assets, including goodwill. There were no impairment or FV less costs to sell adjustments recorded in 2026.
The Company will continue to record depreciation on the NMGC assets through the transaction closing date, as the depreciation continues to be reflected in customer rates and will be reflected in the carryover basis of the assets when sold. Depreciation and amortization of $134 million ($97 million USD) was recorded on these assets from August 5, 2024, the date they were classified as held for sale, through June 30, 2026. Of the $134 million ($97 million USD) recorded to date, $37 million ($27 million USD) was recorded in 2026.
Cybersecurity Incident
On April 25, 2025, Emera and NSPI discovered a cybersecurity incident involving unauthorized access into certain parts of its Canadian IT network and servers supporting portions of its business applications (the “Cybersecurity Incident’). There was no disruption to the Canadian physical operations or Emera’s US or Caribbean utilities’ operations.
16
The Company implemented business continuity processes for certain impacted business and administrative functions at its Canadian affiliates. The systematic restoration of affected IT systems and corresponding transition away from business continuity processes is substantially complete. For more information on the impact on internal controls over financial reporting, refer to the “Disclosure and Internal Controls” section. The Company maintains cyber insurance coverage and is working with its insurer on the claims process. At this time, the Cybersecurity Incident is not expected to have a material impact on the Company’s financial position or results of operations. For information on risks associated with cybersecurity incidents generally, refer to the “Enterprise Risk and Risk Management” section in the Company’s 2025 annual MD&A.
FINANCIAL HIGHLIGHTS
Florida Electric Utility
| For the | Three months ended June 30 |
Six months ended June 30 |
||||||||||||||
| millions of USD (except as indicated) | 2026 | 2025 | 2026 | 2025 | ||||||||||||
| Operating revenues – regulated electric |
$ | 862 | $ | 839 | $ | 1,664 | $ | 1,488 | ||||||||
| Regulated fuel for generation and purchased power |
$ | 181 | $ | 188 | $ | 395 | $ | 349 | ||||||||
| Contribution to consolidated net income |
$ | 189 | $ | 188 | $ | 320 | $ | 302 | ||||||||
| Contribution to consolidated net income – CAD |
$ | 261 | $ | 260 | $ | 441 | $ | 424 | ||||||||
| Electric sales volumes (Gigawatt hours (“GWh”)) |
5,341 | 5,400 | 10,052 | 10,036 | ||||||||||||
| Electric production volumes (GWh) |
5,943 | 5,925 | 10,698 | 10,561 | ||||||||||||
| Average fuel cost in dollars per megawatt hour (“MWh”) |
$ | 30 | $ | 32 | $ | 37 | $ | 33 | ||||||||
The impact of the change in FX rates was minimal for the three months ended June 30, 2026, and decreased CAD earnings for the six months ended June 30, 2026, by $8 million.
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | Six months ended | ||||||
| millions of USD | June 30 | June 30 | ||||||
| Contribution to consolidated net income – 2025 |
$ | 188 | $ | 302 | ||||
| Increased operating revenues due to new base rates and customer growth. Year-over-year also increased due to storm cost recovery revenue (offset in OM&G) and increased off-system sales | 23 | 176 | ||||||
| Decreased fuel for generation and purchased power quarter-over-quarter due to a decrease in purchased power resulting from the timing of production outages and lower natural gas prices. Year-over-year increase due to higher natural gas prices | 7 | (46) | ||||||
| Increased OM&G year-over-year due to higher storm cost recognition (offset in revenue) and timing of production outage costs, partially offset by decreased regulatory deferrals | (1) | (52) | ||||||
| Increased depreciation and amortization due to increased PP&E placed in service | (13) | (25) | ||||||
| Increased interest expense due to higher debt balances | (7) | (14) | ||||||
| Increased state and municipal taxes due to higher revenues | (6) | (15) | ||||||
| Other | (2) | (6) | ||||||
| Contribution to consolidated net income – 2026 |
$ | 189 | $ | 320 | ||||
17
Canadian Electric Utilities
| Three months ended | Six months ended | |||||||||||||||
| For the | June 30 | June 30 | ||||||||||||||
| millions of dollars (except as indicated) | 2026 | 2025 | 2026 | 2025 | ||||||||||||
| Operating revenues – regulated electric |
$ | 448 | $ | 436 | $ | 1,060 | $ | 1,035 | ||||||||
| Regulated fuel for generation and purchased power (1) |
$ | 226 | $ | 215 | $ | 543 | $ | 574 | ||||||||
| Contribution to consolidated net income |
$ | 16 | $ | 17 | $ | 102 | $ | 138 | ||||||||
| Electric sales volumes (GWh) |
2,506 | 2,373 | 5,933 | 5,706 | ||||||||||||
| Electric production volumes (GWh) |
2,615 | 2,497 | 6,333 | 6,086 | ||||||||||||
| Average fuel costs in dollars per MWh |
$ | 86 | $ | 86 | $ | 86 | $ | 94 | ||||||||
(1) Regulated fuel for generation and purchased power includes NSPI’s FAM on the Condensed Consolidated Statements of Income, however, it is excluded in the segment overview.
Canadian Electric Utilities’ contribution to consolidated net income is summarized in the following table:
| Three months ended | Six months ended | |||||||||||||||
| For the | June 30 | June 30 | ||||||||||||||
| millions of dollars | 2026 | 2025 | 2026 | 2025 | ||||||||||||
| NSPI |
$ | 6 | $ | 6 | $ | 80 | $ | 116 | ||||||||
| Equity investment in NSPML |
10 | 11 | 22 | 22 | ||||||||||||
| Contribution to consolidated net income |
$ | 16 | $ | 17 | $ | 102 | $ | 138 | ||||||||
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | Six months ended | ||||||
| millions of dollars | June 30 | June 30 | ||||||
| Contribution to consolidated net income – 2025 |
$ | 17 | $ | 138 | ||||
| Increased operating revenues at NSPI due to higher commercial and industrial sales volumes and favourable weather, partially offset by changes in electricity pricing effective January 1, 2026 and May 1, 2026. In addition, residential sales volumes decreased operating revenues quarter-over-quarter and increased operating revenues year-over-year | 12 | 25 | ||||||
| Increased regulated fuel for generation and purchased power at NSPI quarter-over-quarter due to higher commodity prices and increased sales volumes, partially offset by decreased Nova Scotia output-based pricing system (“OBPS”) carbon tax. Decreased regulated fuel for generation and purchased power at NSPI year-over-year due to decreased Nova Scotia OBPS carbon tax, partially offset by increased sales volumes. | (11) | 31 | ||||||
| Decreased FAM deferral at NSPI year-over-year primarily due to lower under-recovery of fuel costs | (2) | (57) | ||||||
| Increased OM&G at NSPI year-over-year due to higher storm restoration costs, lower administrative overhead allocated to PP&E, and higher costs for transmission and distribution operations. These were partially offset by lower costs year-over-year related to the Cybersecurity Incident and recovery of deferred storm costs | - | (9) | ||||||
| Increased depreciation and amortization at NSPI due to increased PP&E placed in service | (1) | (7) | ||||||
| Decreased income tax recovery year-over-year as a result of higher clean technology investment tax credits in 2025 at NSPI | (2) | (19) | ||||||
| Other | 3 | - | ||||||
| Contribution to consolidated net income – 2026 | $ | 16 | $ | 102 | ||||
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Gas Utilities and Infrastructure
On August 5, 2024, Emera announced an agreement to sell NMGC. On July 30, 2026, the NMPRC issued a final order approving the transaction, which is expected to close in August 2026. For more information on the pending transaction, refer to the “Other Developments” section.
| Three months ended | Six months ended | |||||||||||||||
| For the | June 30 | June 30 | ||||||||||||||
| millions of USD (except as indicated) | 2026 | 2025 | 2026 | 2025 | ||||||||||||
| Operating revenues – regulated gas (1) |
$ | 270 | $ | 256 | $ | 688 | $ | 681 | ||||||||
| Operating revenues – non-regulated |
4 | 4 | 8 | 8 | ||||||||||||
| Total operating revenue |
$ | 274 | $ | 260 | $ | 696 | $ | 689 | ||||||||
| Regulated cost of natural gas |
$ | 43 | $ | 53 | $ | 156 | $ | 206 | ||||||||
| Contribution to consolidated net income |
$ | 39 | $ | 35 | $ | 138 | $ | 118 | ||||||||
| Contribution to consolidated net income – CAD |
$ | 55 | $ | 48 | $ | 191 | $ | 168 | ||||||||
| Gas sales volumes (millions of Therms) |
733 | 759 | 1,592 | 1,616 | ||||||||||||
(1) Operating revenues – regulated gas includes $11 million of finance income from Brunswick Pipeline (2025 – $11 million) for the three months ended June 30, 2026 and $22 million (2025 – $23 million) for the six months ended June 30, 2026.
Gas Utilities and Infrastructure’s contribution to consolidated net income is summarized in the following table:
| $ | $ | $ | $ | |||||||||||||
| Three months ended | Six months ended | |||||||||||||||
| For the | June 30 | June 30 | ||||||||||||||
| millions of USD | 2026 | 2025 | 2026 | 2025 | ||||||||||||
| PGS |
$ | 36 | $ | 25 | $ | 91 | $ | 65 | ||||||||
| NMGC |
(6) | 2 | 29 | 36 | ||||||||||||
| Other |
9 | 8 | 18 | 17 | ||||||||||||
| Contribution to consolidated net income |
$ | 39 | $ | 35 | $ | 138 | $ | 118 | ||||||||
The impact of the change in FX rates was minimal for the three months ended June 30, 2026, and decreased CAD earnings for the six months ended June 30, 2026 by $6 million.
Highlights of the net income changes are summarized in the following table:
| $ | $ | |||||||
| For the | Three months ended | Six months ended | ||||||
| millions of USD | June 30 | June 30 | ||||||
| Contribution to consolidated net income – 2025 |
$ | 35 | $ | 118 | ||||
| Increased gas revenues due to increased rates and higher-off system sales at PGS, partially offset by lower fuel revenue at NMGC | 14 | 7 | ||||||
| Decreased cost of natural gas due to lower natural gas prices at NMGC. Year-over-year partially offset by higher natural gas prices at PGS | 10 | 50 | ||||||
| Increased OM&G, primarily due to higher labour and benefit costs at NMGC and PGS | (12) | (15) | ||||||
| Increased depreciation primarily due to PP&E placed in service at PGS and NMGC | (3) | (7) | ||||||
| Increased income tax expense primarily due to increased income before provision for income taxes at PGS | (2) | (8) | ||||||
| Other | (3) | (7) | ||||||
| Contribution to consolidated net income – 2026 | $ | 39 | $ | 138 | ||||
19
Other Electric Utilities
On May 12, 2026, Emera completed the sale of GBPC. For further details, refer to the “Significant Items Affecting Earnings” and “Other Developments” sections.
| $ | $ | $ | $ | |||||||||||||
| Three months ended | Six months ended | |||||||||||||||
| For the | June 30 | June 30 | ||||||||||||||
| millions of USD (except as indicated) | 2026 | 2025 | 2026 | 2025 | ||||||||||||
| Operating revenues – regulated electric |
$ | 97 | $ | 104 | $ | 189 | $ | 196 | ||||||||
| Regulated fuel for generation and purchased power |
$ | 57 | $ | 53 | $ | 101 | $ | 100 | ||||||||
| Contribution to consolidated adjusted net income |
$ | 3 | $ | 9 | $ | 10 | $ | 9 | ||||||||
| Loss on sale of GBPC |
(12 | ) | - | (12 | ) | - | ||||||||||
| Equity securities MTM gain |
1 | 1 | - | 1 | ||||||||||||
| Contribution to consolidated net income |
$ | (8 | ) | $ | 10 | $ | (2 | ) | $ | 10 | ||||||
| Contribution to consolidated adjusted net income – CAD |
$ | 5 | $ | 12 | $ | 13 | $ | 12 | ||||||||
| Contribution to consolidated net income – CAD |
$ | (10 | ) | $ | 14 | $ | (3 | ) | $ | 14 | ||||||
| Electric sales volumes (GWh) |
290 | 325 | 596 | 628 | ||||||||||||
| Electric production volumes (GWh) |
313 | 346 | 639 | 668 | ||||||||||||
| Average fuel costs in dollars per MWh |
$ | 182 | $ | 153 | $ | 158 | $ | 150 | ||||||||
Other Electric Utilities’ contribution to consolidated adjusted net income is summarized in the following table:
| $ | $ | $ | $ | |||||||||||||
| Three months ended | Six months ended | |||||||||||||||
| For the | June 30 | June 30 | ||||||||||||||
| millions of USD | 2026 | 2025 | 2026 | 2025 | ||||||||||||
| BLPC |
$ | 3 | $ | 4 | $ | 8 | $ | 6 | ||||||||
| GBPC |
(1) | 5 | 1 | 3 | ||||||||||||
| Other |
1 | - | 1 | - | ||||||||||||
| Contribution to consolidated adjusted net income |
$ | 3 | $ | 9 | $ | 10 | $ | 9 | ||||||||
The impact of the change in FX rates on CAD earnings for the three and six months ended June 30, 2026 was minimal.
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | Six months ended | ||||||
| millions of USD | June 30 | June 30 | ||||||
| Contribution to consolidated net income – 2025 |
$ | 10 | $ | 10 | ||||
| Decreased operating revenues – regulated electric due to sale of GBPC in Q2 2026, partially offset by higher fuel revenue at BLPC as a result of higher fuel prices | (7) | (7) | ||||||
| Increased regulated fuel for generation and purchased power due to higher fuel costs at BLPC, partially offset by the sale of GBPC | (4) | (1) | ||||||
| Decreased OM&G due to sale of GBPC | 4 | 5 | ||||||
| Loss on sale of GBPC | (12) | (12) | ||||||
| Other | 1 | 3 | ||||||
| Contribution to consolidated net income – 2026 |
$ | (8) | $ | (2) | ||||
20
Other
| Three months ended | Six months ended | |||||||||||||||
| For the | June 30 | June 30 | ||||||||||||||
| millions of dollars | 2026 | 2025 | 2026 | 2025 | ||||||||||||
| Marketing and trading margin (1)(2) |
$ | (28) | $ | (19) | $ | 155 | $ | 101 | ||||||||
| Other non-regulated operating revenue |
8 | 7 | 22 | 16 | ||||||||||||
| Total operating revenues – non-regulated |
$ | (20) | $ | (12) | $ | 177 | $ | 117 | ||||||||
| Contribution to consolidated adjusted net (loss) income |
$ | (125) | $ | (101) | $ | (120) | $ | (127) | ||||||||
| MTM (loss) gain, after-tax (3) |
(89) | (31) | 59 | 173 | ||||||||||||
| Loss on sale of GBPC, after tax and transaction costs (4) |
(3) | - | (3) | - | ||||||||||||
| Charges related to the pending sale of NMGC, after-tax (5) |
- | (72) | - | (72) | ||||||||||||
| Contribution to consolidated net (loss) income |
$ | (217) | $ | (204) | $ | (64) | $ | (26) | ||||||||
(1) Marketing and trading margin represents EES’s purchases and sales of natural gas and electricity, pipeline and storage capacity costs and energy asset management services’ revenues.
(2) Marketing and trading margin excludes a pre-tax MTM loss of $104 million for the three months ended June 30, 2026 (2025 – $91 million loss) and a gain of $107 million for the six months ended June 30, 2026 (2025 – $197 million gain).
(3) Net of income tax recovery of $37 million for the three months ended June 30, 2026 (2025 – $13 million recovery) and $24 million income tax expense for the six months ended June 30, 2026 (2025 – $71 million expense).
(4) Net of income tax recovery of $2 million for the three and six months ended June 30, 2026.
(5) Includes an impairment charge of $75 million ($71 million after-tax) and transaction costs of $2 million ($1 million after-tax) for the three and six months ended June 30, 2025.
Other’s contribution to consolidated adjusted net (loss) income is summarized in the following table:
| Three months ended | Six months ended | |||||||||||||||
| For the | June 30 | June 30 | ||||||||||||||
| millions of dollars | 2026 | 2025 | 2026 | 2025 | ||||||||||||
| Emera Energy |
||||||||||||||||
| EES |
$ | (24) | $ | (14) | $ | 81 | $ | 55 | ||||||||
| Other |
9 | (3) | 11 | (4) | ||||||||||||
| Corporate – see breakdown of contribution below |
(110) | (84) | (212) | (178) | ||||||||||||
| Contribution to consolidated adjusted net (loss) income |
$ | (125) | $ | (101) | $ | (120) | $ | (127) | ||||||||
21
Highlights of the net income changes are summarized in the following table:
| For the | Three months ended | Six months ended | ||||||
| millions of dollars | June 30 | June 30 | ||||||
| Contribution to consolidated net (loss) income – 2025 |
$ | (204) | $ | (26) | ||||
| Decreased marketing and trading margin quarter-over-quarter due to timing of hedge settlements related to EES’ storage positions and higher transport costs. Increased marketing and trading margin year-over-year due to favourable weather conditions in Q1 that led to higher natural gas prices and increased volatility that created profitable opportunities | (9) | 54 | ||||||
| Increased OM&G at Corporate primarily due to a lower gain on the long-term incentive hedge and increased costs as a result of the NYSE listing | (1) | (13) | ||||||
| Increased equity earnings at Bear Swamp due to business interruption insurance received related to an unplanned outage in 2025 and higher generation | 19 | 23 | ||||||
| Increased Corporate FX losses on the translation of USD short-term debt balances. Year-over-year is partially offset by a decreased realized loss on FX hedges | (9) | (4) | ||||||
| Increased interest expense due to higher long-term debt resulting from the timing of financings, partially offset by interest earned on debt proceeds held in invested cash. Year-over-year is also partially offset by lower short-term debt | (21) | (28) | ||||||
| Decreased income tax recovery quarter-over-quarter due to an unfavourable impact of foreign currency translation. Decreased income tax recovery year-over-year due to decreased loss before provision for income taxes and an unfavourable impact of foreign currency translation | (3) | (15) | ||||||
| Unfavourable changes in MTM, after-tax, due to a loss on Corporate FX hedges compared to gain in prior year and amortization of gas transportation assets and changes in existing positions at EES | (58) | (114) | ||||||
| Charges related to the pending sale of NMGC, after-tax | 72 | 72 | ||||||
| Other | (3) | (13) | ||||||
| Contribution to consolidated net (loss) income – 2026 |
$ | (217) | $ | (64) | ||||
22
Corporate
Corporate’s adjusted loss is summarized in the following table:
| Three months ended | Six months ended | |||||||||||||||
| For the | June 30 | June 30 | ||||||||||||||
| millions of dollars | 2026 | 2025 | 2026 | 2025 | ||||||||||||
| Operating expenses (1) |
$ | (22) | $ | (20) | $ | (41) | $ | (27) | ||||||||
| Interest expense |
(112) | (91) | (215) | (187) | ||||||||||||
| Income tax recovery |
43 | 40 | 83 | 74 | ||||||||||||
| Preferred dividends |
(19) | (19) | (39) | (37) | ||||||||||||
| Other (2)(3) |
- | 6 | - | (1) | ||||||||||||
| Corporate adjusted net loss (4)(5)(6) |
$ | (110) | $ | (84) | $ | (212) | $ | (178) | ||||||||
(1) Operating expenses include OM&G and depreciation.
(2) Other includes realized gains and losses on FX hedges entered into to hedge USD denominated operating unit earnings exposure.
(3) Includes a realized net loss, pre-tax of $1 million ($1 million after-tax) for the three months ended June 30, 2026 (2025 – $2 million net loss, pre-tax and $2 million loss, after-tax) and a $1 million net loss, pre-tax ($1 million after-tax) for the six months ended June 30, 2026 (2025 – $10 million net loss, pre-tax and $7 million loss, after-tax) on FX hedges, as discussed above.
(4) Excludes a MTM loss, after-tax, of $12 million for the three months ended June 30, 2026 (2025 – $30 million gain, after-tax) and a MTM loss, after-tax of $17 million for the six months ended June 30, 2026 (2025 – $33 million gain, after-tax).
(5) Excludes certain charges related to the pending sale of NMGC of $77 million ($72 million after-tax) for the three and six months ended June 30, 2025.
(6) Excludes loss on the sale of GBPC of $5 million ($3 million after-tax) for the three and six months ended June 30, 2025.
LIQUIDITY AND CAPITAL RESOURCES
The Company generates internally sourced cash from its various regulated and non-regulated energy investments. Utility customer bases are diversified by both sales volumes and revenues among customer classes. Emera’s non-regulated businesses provide diverse revenue streams and counterparties to the business. Circumstances that could affect the Company’s ability to generate cash include changes to global macro-economic conditions, downturns in markets served by Emera, impact of fuel commodity price changes on collateral requirements and timely recoveries of fuel and storm costs from customers, the loss of one or more large customers, regulatory decisions affecting customer rates and the recovery of regulatory assets, and changes in environmental legislation. Emera’s subsidiaries are generally in a financial position to contribute cash dividends to Emera provided they do not breach their debt covenants, where applicable, after giving effect to the dividend payment, and that they maintain their credit metrics.
Emera’s future liquidity and capital needs will be predominately for working capital requirements, ongoing rate base investment, business acquisitions, greenfield development, dividends and debt servicing. Emera has an approximate $20 billion capital investment plan over the 2026 through 2030 period to support ongoing growth. Capital investments at Emera’s regulated utilities are subject to regulatory approval.
Emera has sufficient liquidity to service debt obligations as they come due and to meet any near-term capital investment requirements as currently planned. Emera plans to use cash from operations, debt raised at the utilities, corporate equity, and proceeds from the pending sale of NMGC to support normal operations, repayment of existing debt, and capital requirements. Debt raised at certain of the Company’s utilities is subject to applicable regulatory approvals. Generally, Corporate equity requirements in support of the Company’s capital investment plan are expected to be funded through issuance of hybrid securities and issuance of common equity through Emera’s DRIP and ATM programs.
Emera has total committed credit facilities with varying maturities that cumulatively provide $3.3 billion CAD and $2.1 billion USD of credit, with approximately $1.0 billion CAD and $1.0 billion USD undrawn and available at June 30, 2026. The Company was holding a cash balance of $400 million, which includes $4 million classified as assets held for sale, related to the pending sale of NMGC, at June 30, 2026. For further discussion, refer to the “Debt Management” section below.
23
Consolidated Cash Flow Highlights
Significant changes in the Condensed Consolidated Statements of Cash Flows between the six months ended June 30, 2026 and 2025 include:
| $ | $ | $ | ||||||||||
| millions of dollars | 2026 | 2025 | Change | |||||||||
| Cash, cash equivalents, restricted cash, and cash associated with assets held for sale, beginning of period | $ | 371 | $ | 221 | $ | 150 | ||||||
| Provided by (used in): |
||||||||||||
| Operating cash flow before changes in working capital |
1,411 | 1,306 | 105 | |||||||||
| Changes in non-cash working capital |
(9) | (507) | 498 | |||||||||
| Operating activities |
$ | 1,402 | $ | 799 | $ | 603 | ||||||
| Investing activities |
(1,531) | (1,672) | 141 | |||||||||
| Financing activities |
95 | 877 | (782) | |||||||||
| Effect of exchange rate changes on cash, cash equivalents, restricted cash, and cash associated with assets held for sale | 74 | (7) | 81 | |||||||||
| Cash, cash equivalents, restricted cash and cash associated with assets held for sale, end of period | $ | 411 | $ | 218 | $ | 193 | ||||||
Cash Flow from Operating Activities
Net cash provided by operating activities increased $603 million to $1,402 million for the six months ended June 30, 2026, compared to $799 million for the same period in 2025.
Cash from operations before changes in working capital increased $105 million year-over-year. This increase was due to lower fuel under-recoveries and higher storm cost recoveries at TEC, and higher marketing and trading margin at EES. These were partially offset by higher Corporate costs, lower current income tax recovery at NSPI as a result of higher clean energy technology investment tax credits in 2025 and a purchased gas adjustment refund to customers at NMGC.
Changes in non-cash working capital increased operating cash flow by $498 million year-over-year. This increase was due to favourable changes in accounts payable at TEC due to timing of storm invoice payments, timing of settlements and favourable changes in posted margin at EES, timing of Corporate interest payments and favourable changes in accounts receivable at NSPI. These were partially offset by unfavourable changes in accounts payable due to timing and unfavourable changes in fuel inventory due to increased purchases at NSPI, and unfavourable changes in accounts receivable at PGS due to new base rates.
Cash Flow from Investing Activities
Net cash used in investing activities decreased $141 million to $1,531 million for the six months ended June 30, 2026, compared to $1,672 million for the same period in 2025. The decrease was due to proceeds from sale of GBPC, partially offset by higher capital investment and lower proceeds from disposal of assets.
Capital investments, including AFUDC, for the six months ended June 30, 2026, were $1,781 million, compared to $1,757 million for the same period in 2025. Details of the 2026 capital investment by segment are shown below:
| • | $1,142 million – Florida Electric Utility (2025 – $1,108 million); |
| • | $265 million – Canadian Electric Utilities (2025 – $319 million); |
| • | $340 million – Gas Utilities and Infrastructure (2025 – $288 million); |
| • | $30 million – Other Electric Utilities (2025 – $41 million); and |
| • | $4 million – Other (2025 – $1 million). |
24
Cash Flow from Financing Activities
Net cash provided by financing activities decreased $782 million to $95 million for the six months ended June 30, 2026, compared to $877 million for the same period in 2025. This decrease was due to the retirement of Corporate long-term debt, lower issuances of long-term debt at TEC and lower net proceeds from committed facilities and short-term debt at NSPI. These were partially offset by higher proceeds from long-term debt and short-term debt at Corporate, higher net borrowing on committed credit facilities at TEC, higher net issuances of long-term debt at NSPI, higher proceeds from long-term debt at PGS and higher issuance of common shares.
Contractual Obligations
As at June 30, 2026, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:
| millions of dollars | 2026 | 2027 | 2028 | 2029 | 2030 | Thereafter | Total | |||||||||||||||||||||
| Long-term debt principal (1)(2) |
$ | 22 | $ | 67 | $ | 722 | $ | 2,034 | $ | 512 | $ | 17,256 | $ | 20,613 | ||||||||||||||
| Interest payment obligations (3)(4) |
519 | 1,021 | 1,003 | 935 | 888 | 12,130 | 16,496 | |||||||||||||||||||||
| Purchased power (5) |
206 | 432 | 413 | 461 | 454 | 6,423 | 8,389 | |||||||||||||||||||||
| Transportation (6)(7) |
576 | 739 | 557 | 473 | 407 | 3,104 | 5,856 | |||||||||||||||||||||
| Fuel, gas supply and storage (8) |
388 | 322 | 151 | 198 | 81 | 58 | 1,198 | |||||||||||||||||||||
| Capital projects |
249 | 88 | 45 | 1 | 9 | - | 392 | |||||||||||||||||||||
| Pension and post-retirement obligations (9) |
14 | 29 | 29 | 28 | 25 | 246 | 371 | |||||||||||||||||||||
| Asset retirement obligations |
5 | 1 | 2 | 1 | 1 | 748 | 758 | |||||||||||||||||||||
| Other |
94 | 97 | 186 | 61 | 49 | 323 | 810 | |||||||||||||||||||||
| $ | 2,073 | $ | 2,796 | $ | 3,108 | $ | 4,192 | $ | 2,426 | $ | 40,288 | $ | 54,883 | |||||||||||||||
As detailed below, contractual obligations at June 30, 2026 includes those related to NMGC. On completion of the sale of NMGC, all remaining future contractual obligations will be transferred to the buyer. For further details on the pending transaction, refer to the “Other Developments” section.
(1) Includes $786 million related to NMGC in thereafter.
(2) The Company has hybrid notes that mature in 2054, 2056, and 2076. These maturity dates have been used in the computation of the Company’s long-term debt principal and interest payment obligations at June 30, 2026. The Company has the option to repay such notes in advance of maturity upon exercise of the Company’s redemption rights in accordance with terms of the applicable indenture.
(3) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at June 30, 2026, including any expected required payment under associated swap agreements.
(4) Includes $393 million related to NMGC (2026: $14 million, 2027: $34 million, 2028: $34 million, 2029: $34 million, 2030: $34 million, and $243 million thereafter).
(5) Annual requirement to purchase electricity from Independent Power Producers or other utilities over varying contract lengths.
(6) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $121 million related to a gas transportation contract between PGS and SeaCoast through 2040, and $20 million of future performance obligations related to asset management agreements between PGS and EES through 2030.
(7) Includes $167 million related to NMGC (2026: $15 million, 2027: $35 million, 2028: $32 million, 2029: $22 million, 2030: $21 million, and $42 million thereafter).
(8) Includes $284 million related to NMGC (2026: $54 million, 2027: $102 million, 2028: $45 million, 2029: $42 million, and 2030: $41 million).
(9) Includes the estimated contractual obligation, which is calculated as the current legislatively required contributions to the registered funded pension plans, plus the estimated costs of further benefit accruals contracted under NSPI’s Collective Bargaining Agreement and estimated benefit payments related to other unfunded benefit plans.
NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. On May 11, 2026, the NSEB issued its decision on NSPML’s 2026 assessment application, approving the collection of up to $198 million from NSPI for recovery of costs associated with the Maritime Link in 2026, subject to a monthly holdback of up to $4 million. The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to NSEB approval.
25
Emera has committed to obtain certain transmission rights in New Brunswick during summer periods (April through October, inclusive) for Newfoundland and Labrador Hydro’s (“NLH”) use, if requested, effective August 15, 2021 and continuing for 50 years. As transmission rights are contracted, the obligations are included within “Other” in the above table.
Debt Management
In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to unsecured committed syndicated revolving and non-revolving bank lines of credit in either CAD or USD, per the table below as at June 30, 2026.
| millions of dollars in currency as noted below
|
Maturity | Credit Facilities |
Utilized | Undrawn and Available |
||||||||||||
| In CAD: |
||||||||||||||||
| Emera – committed revolving credit facility |
June 2031 | $ | 1,300 | $ | 627 | $ | 673 | |||||||||
| NSPI – committed revolving credit facility |
June 2031 | 800 | 430 | 370 | ||||||||||||
| NSPI – non-revolving facility |
May 2027 | 500 | 500 | - | ||||||||||||
| Emera – non-revolving facility |
June 2027 | 500 | 500 | - | ||||||||||||
| Emera – non-revolving facility |
February 2027 | 200 | 200 | - | ||||||||||||
| In USD: |
||||||||||||||||
| TEC – committed revolving credit facility |
November 2030 | 1,200 | 802 | 398 | ||||||||||||
| TECO Finance – committed revolving credit facility |
November 2030 | 400 | 30 | 370 | ||||||||||||
| PGS – committed revolving facility |
November 2030 | 250 | 90 | 160 | ||||||||||||
| NMGC – revolving credit facility (1) |
December 2027 | 125 | 19 | 106 | ||||||||||||
| NMGC – committed non-revolving facility (1) |
October 2026 | 70 | 70 | - | ||||||||||||
| Other – committed revolving credit facilities |
Various | 8 | - | 8 | ||||||||||||
(1) On August 5, 2024, Emera announced an agreement to sell NMGC. As a result, NMGC’s assets and liabilities were classified as held for sale beginning in Q3 2024. For further details on the pending transaction, refer to the “Other Developments” section.
Emera and its subsidiaries have certain financial and other covenants associated with their debt and credit facilities. Covenants are tested regularly, and the Company is in compliance with covenant requirements as at June 30, 2026.
Recent significant financing activity for Emera and its subsidiaries are discussed below by segment:
Canadian Electric Utilities
On July 14, 2026, the holders of NSPI’s $40 million senior unsecured notes exercised their option to extend the maturity date from August 14, 2026, to August 14, 2056.
On June 19, 2026, NSPI amended its $800 million revolving credit facility to extend the maturity date from June 24, 2029, to June 19, 2031. There were no other material changes in commitment amount, maturity, or interest from the prior agreement.
On May 1, 2026, NSPI amended its $500 million non-revolving facility to extend the maturity date from May 21, 2026, to May 21, 2027. There were no other material changes in commercial terms from the prior agreement.
On April 17, 2026, NSPI issued $300 million in unsecured notes that bear interest at 3.95 per cent with a maturity date of April 17, 2031. Proceeds from this issuance have been used for general corporate purposes, including repayment of existing debt.
26
Gas Utilities and Infrastructure
On June 30, 2026, NMGC executed an agreement to issue $140 million USD in senior unsecured notes. The agreement included $70 million USD senior unsecured notes that bear interest at 5.35 per cent with a maturity date of July 28, 2031, and $70 million USD senior unsecured notes that bear interest at 5.73 per cent with a maturity date of October 20, 2036. Proceeds from the notes due in 2031 were received on July 28, 2026, and were used for the repayment of maturing long-term debt. Proceeds from notes due in 2036 will be received on October 20, 2026, and will be used for the repayment of short-term debt outstanding. Therefore, $140 million USD of short-term debt was classified as long-term liabilities associated with held for sale as of June 30, 2026.
On May 5, 2026, PGS executed an agreement to issue $200 million USD in senior notes. The agreement included $50 million USD senior notes (“Series A”) that bear interest at 4.91 per cent with a maturity date of May 5, 2031, $100 million USD senior notes (“Series B”) that bear interest at 5.39 per cent with a maturity date of May 5, 2036, and $50 million USD senior notes (“Series C”) that bear interest at 5.64 per cent with a maturity date of August 20, 2041. Proceeds from Series A and Series B were used for the repayment of short-term debt outstanding. Proceeds from Series C will be received on August 20, 2026, and will be used for general corporate purposes, including repayment of existing debt.
Other Electric Utilities
On March 18, 2026, BLPC amended its $10 million USD note to extend the maturity date from March 2026 to May 2031, reduced the interest rate from 2.05 per cent to 1.90 per cent, and change the principal payment from $0.25 million USD quarterly to $0.5 million USD semi-annually.
On February 9, 2026, BLPC entered into a $46 million USD non-revolving facility which matures in 2031 and bears interest at 1.80 per cent. As of June 30, 2026, BLPC has drawn $44 million USD on the facility.
Other
On June 19, 2026, Emera amended its $1.3 billion revolving credit facility to extend the maturity date from June 24, 2029, to June 19, 2031. There were no other material changes in commercial terms from the prior agreement.
On June 4, 2026, Emera entered into a $500 million non-revolving facility which matures on June 4, 2027. The credit agreement contains customary representations and warranties, events of default and financial and other covenants. The non-revolving facility’s interest rates are referenced to the Term CORRA or prime rate, plus a margin. Proceeds from this facility were used for repayment of existing debt and general corporate purposes.
On March 4, 2026, EUSHI Finance Inc. (“EUSHI Finance”), Emera Finance, Emera US Holdings Inc. (“EUSHI”) and Emera filed a new shelf registration statement on Form F-10 and Form F-3 (“Registration Statement”), with the Nova Scotia Securities Commission (“NSSC”) and the US Securities and Exchange Commission (“SEC”) under the US/Canada Multijurisdictional Disclosure System. The Registration Statement was filed in connection with the prospective offer and issue by EUSHI Finance or Emera Finance of one or more series of senior and/or subordinated unsecured debt securities (“Debt Securities”), in an aggregate principal amount of up to $2.25 billion USD, during the 25-month period that the short form base shelf prospectus contained in the Registration Statement (“Base Shelf Prospectus”), including any further amendments thereto, remains valid. The Debt Securities may be offered in one or more transactions, at prices, with maturities and on terms to be set forth in one or more prospectus supplements to be filed with the NSSC and the SEC at the time of any such offering.
27
On March 23, 2026, Emera Finance completed an issuance of $750 million USD aggregate principal amount of fixed-to-fixed reset rate junior subordinated notes, pursuant to the prospectus supplement, dated March 23, 2026, to the Base Shelf Prospectus. The issuance consisted of $375 million USD aggregate principal amount of 6.65 per cent Series A fixed-to-fixed reset rate junior subordinated notes due 2056 and $375 million USD aggregate principal amount of 6.85 per cent Series B fixed-to-fixed reset rate junior subordinated notes due 2056 (collectively, the “Notes”). The Notes are fully and unconditionally guaranteed, on a joint, several and subordinated basis, by Emera and EUSHI.
On March 27, 2026, Emera Finance completed an issuance of $750 million USD aggregate principal amount of senior notes pursuant to the prospectus supplement, dated March 27, 2026, to the Base Shelf Prospectus. The issuance consisted of $450 million USD aggregate principal amount of senior notes that bear interest at a rate of 4.50 per cent with a maturity date of April 1, 2029 and $300 million USD aggregate principal amount of senior notes that bear interest at a rate of 5.20 per cent with a maturity date of April 1, 2033. The senior notes are fully and unconditionally guaranteed, on a joint and several basis, by Emera and EUSHI.
Together these issuances were used to redeem all $1.2 billion USD of Emera’s outstanding 6.75 per cent fixed-to-floating subordinated notes - Series 2016-A due 2076, and to repay Emera US Finance’s $750 million USD 3.55 per cent senior unsecured note on June 15, 2026, upon maturity.
On February 20, 2026, Emera amended its $200 million unsecured non-revolving facility to extend the maturity date from February 20, 2026 to February 19, 2027. There were no other material changes to the terms from the prior agreement.
Credit Ratings
Emera’s credit ratings are consistent with those disclosed in the Company’s 2025 annual MD&A, with material updates noted below:
On May 20, 2026, Moody’s Ratings revised its outlook on Emera and TEC to stable from negative with no changes to existing ratings.
Guarantees and Letters of Credit
Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2025
annual MD&A, with material updates as noted below:
The Company has standby letters of credit and surety bonds in the amount of $174 million USD (December 31, 2025 – $271 million USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed annually, as required.
Emera, on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The expiry date of this letter of credit was extended to June 2027. The amount committed as at June 30, 2026 was $72 million (December 31, 2025 – $70 million).
Emera’s guarantee of $66 million USD relating to outstanding notes of ECI was automatically terminated in Q2 2026, and no obligations remain outstanding.
28
Outstanding Stock Data
Common Stock
| millions of | millions of | |||||||
| Issued and outstanding: | shares | dollars | ||||||
| Balance, December 31, 2025 |
301.76 | $ | 9,387 | |||||
| Issuance of common stock under ATM program (1) |
2.66 | 184 | ||||||
| Issued under the DRIP, net of discounts |
2.08 | 141 | ||||||
| Senior management stock options exercised and Employee Share Purchase Plan |
0.65 | 38 | ||||||
| Balance, June 30, 2026 |
307.15 | $ | 9,750 | |||||
(1) For the three months ended June 30, 2026, no common shares were issued under Emera’s ATM program. For the six months ended June 30, 2026, a total of 2,657,496 common shares were issued under Emera’s ATM program at an average price of $69.89 per share for gross proceeds of $186 million ($184 million, net of after-tax issuance costs). As at June 30, 2026, an aggregate gross sales limit of $414 million remained available for issuance under the ATM program.
As at August 5, 2026, the amount of issued and outstanding common shares was 307.2 million.
If all outstanding stock options were converted as at August 5, 2026, an additional 4.3 million common shares would be issued and outstanding.
Preferred Stock
As at August 5, 2026, Emera had the following preferred shares issued and outstanding: Series A – 6.0 million; Series C – 10.0 million; Series E – 5.0 million; Series F – 8.0 million; Series H – 12.0 million; Series J – 8.0 million, and Series L – 9.0 million. Emera’s preferred shares do not have voting rights unless the Company fails to pay, in aggregate, eight quarterly dividends.
On April 9, 2026, Emera announced that it would not redeem the currently outstanding Cumulative Minimum Rate Reset First Preferred Shares, Series J (“Series J Shares”) on May 15, 2026 (the “Conversion Date”).
On April 15, 2026, Emera announced a dividend rate of 6.345 per cent per annum on the Series J Shares during the five-year period commencing on May 15, 2026, and ending on (and inclusive of) May 14, 2031. Emera also announced a dividend rate of 5.598 per cent on the Cumulative Floating Rate First Series K Shares (“Series K Shares”) for the three-month period commencing on May 15, 2026, and ending on (inclusive of) August 14, 2026.
During the conversion period between April 15, 2026, and April 30, 2026, the holders of Series J Shares had the right, at their option, to convert all or any of their Series J Shares, on a one-for-one basis, into Series K Shares. On May 5, 2026, Emera announced that after having taken into account all conversion notices received from holders of its outstanding Series J Shares by the April 30, 2026 deadline for conversion notices, less than the 1,000,000 Series J Shares required to give effect to conversions into Series K Shares were tendered for conversion. As a result, in accordance with certain rights, privileges, restrictions and conditions attaching to the Series J Shares, none of Emera’s outstanding Series J Shares were converted into Series K Shares on May 15, 2026. On the Conversion Date there was 8.0 million Series J Shares outstanding.
TRANSACTIONS WITH RELATED PARTIES
In the ordinary course of business, Emera provides energy and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Intercompany balances and intercompany transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities, in accordance with accounting standards for rate-regulated entities. All material amounts are under normal interest and credit terms.
29
Significant transactions between Emera and its associated companies are as follows:
| • | Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Condensed Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $60 million for the three months ended June 30, 2026 (2025 – $42 million) and $100 million for the six months ended June 30, 2026 (2025 – $91 million). NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments. For further details, refer to the “Contractual Obligations” section. |
| • | Natural gas transportation capacity purchases from M&NP are reported in the Condensed Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues – non-regulated, totalled $3 million for the three months ended June 30, 2026 (2025 – $3 million) and $10 million for the six months ended June 30, 2026 (2025 – $11 million). |
As at June 30, 2026, Emera and its associated companies had $69 million due from related parties (December 31, 2025 – $35 million) recorded in “Receivables and other current assets”, and $35 million due to related parties (December 31, 2025 – $32 million) recorded in “Other Current Liabilities”, on the Condensed Consolidated Balance Sheets.
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
There have been no material changes in Emera’s risk management profile and practices from those disclosed in the Company’s 2025 annual MD&A.
Derivative Assets and Liabilities Recognized on the Balance Sheet
| $ | $ | |||||||
| As at | June 30 | December 31 | ||||||
| millions of dollars | 2026 | 2025 | ||||||
| Regulatory Deferral: |
||||||||
| Derivative instrument assets (1) |
$ | 53 | $ | 24 | ||||
| Derivative instrument liabilities (2) |
(14) | (34) | ||||||
| Regulatory assets (1) |
18 | 36 | ||||||
| Regulatory liabilities (2) |
(36) | (25) | ||||||
| Net asset |
$ | 21 | $ | 1 | ||||
| HFT Derivatives: |
||||||||
| Derivative instrument assets (1) |
$ | 201 | $ | 158 | ||||
| Derivative instrument liabilities (2) |
(646) | (614) | ||||||
| Net liability |
$ | (445) | $ | (456) | ||||
| Other Derivatives: |
||||||||
| Derivative instrument assets (1) |
$ | 32 | $ | 16 | ||||
| Derivative instrument liabilities (2) |
(17) | (1) | ||||||
| Net asset |
$ | 15 | $ | 15 | ||||
(1) Current, other and held for sale assets.
(2) Current, long-term and held for sale liabilities.
30
Realized and Unrealized Gains (Losses) Recognized in Net Income
| $ | $ | $ | $ | |||||||||||||
| Three months ended | Six months ended | |||||||||||||||
| For the | June 30 | June 30 | ||||||||||||||
| millions of dollars | 2026 | 2025 | 2026 | 2025 | ||||||||||||
| Regulatory Deferral: |
||||||||||||||||
| Regulated fuel for generation and purchased power (1) |
$ | (3) | $ | (7) | $ | 4 | $ | (6) | ||||||||
| HFT Derivatives: |
||||||||||||||||
| Non-regulated operating revenues |
$ | 39 | $ | (14) | $ | 380 | $ | 464 | ||||||||
| Other Derivatives: |
||||||||||||||||
| OM&G |
$ | 10 | $ | 5 | $ | 32 | $ | 25 | ||||||||
| Other (expense) income, net |
(16) | 41 | (23) | 37 | ||||||||||||
| Net gains (losses) |
$ | (6) | $ | 46 | $ | 9 | $ | 62 | ||||||||
| Total net gains |
$ | 30 | $ | 25 | $ | 393 | $ | 520 | ||||||||
(1) Realized gains (losses) on derivative instruments settled and consumed in the period, hedging relationships that have been terminated or the hedged transaction is no longer probable. Realized gains (losses) recorded in inventory will be recognized in “Regulated fuel for generation and purchased power” when the hedged item is consumed.
As of June 30, 2026, the unrealized gain in Accumulated Other Comprehensive Income (“AOCI”) was $10 million, after-tax (December 31, 2025 – $10 million, after-tax). For the three and six months ended June 30, 2026, unrealized gains of $1 million ($1 million for the three and six months ended June 30, 2025, respectively) were reclassified from AOCI into interest expense, net.
DISCLOSURE AND INTERNAL CONTROLS
Management is responsible for establishing and maintaining adequate disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as required by Canadian and US Securities laws. The Company’s internal control framework is based on criteria published in the Internal Control - Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer, designed the Company’s DC&P and ICFR as at June 30, 2026, to provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.
Management recognizes the inherent limitations in internal control systems, no matter how well designed. Control systems determined to be appropriately designed can only provide reasonable assurance with respect to the reliability of financial reporting and may not prevent or detect all misstatements.
Change in ICFR
In April 2025, the Company experienced a Cybersecurity Incident that impacted certain financial systems and processes at its Canadian affiliates. As a result, the Company transitioned these to business continuity processes and implemented additional ICFR during this period. Since that time, the Company has restored substantially all the financial systems and transitioned back from corresponding business continuity processes, which resulted in a material change in the Company’s ICFR at its Canadian affiliates during the period ended June 30, 2026. For more information on the Cybersecurity Incident, refer to the “Other Developments” section.
There were no other material changes in the Company’s ICFR during the quarter ended June 30, 2026, that have materially affected, or are reasonably likely to materially affect, the Company’s ICFR.
31
CRITICAL ACCOUNTING ESTIMATES
The preparation of unaudited condensed consolidated interim financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. There were no material changes in the nature of the Company’s critical accounting estimates from those disclosed in Emera’s 2025 annual MD&A.
CHANGES IN ACCOUNTING POLICIES AND PRACTICES
Future Accounting Pronouncements
The Company considers the applicability and impact of all Accounting Standard Updates (“ASU”) issued by the Financial Accounting Standards Board (“FASB”). The following updates have been issued by the FASB but, as allowed, have not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be either not applicable to the Company or to have an insignificant impact on the consolidated financial statements.
Accounting for Environmental Credits and Environmental Credit Obligations
In May 2026, the FASB issued ASU 2026-02, Environmental Credits and Environmental Credit Obligations (Topic 818). This ASU establishes new guidance for the recognition, measurement, presentation, and disclosure of environmental credits (such as renewable energy credits, carbon offsets, and similar instruments) and environmental credit obligations. The ASU is effective for fiscal years beginning after December 15, 2027, and interim periods within those fiscal years. Early adoption is permitted. An entity must apply the guidance retrospectively through a cumulative-effect adjustment to retained earnings. The Company is currently evaluating the impact of adoption of the standard update on its consolidated financial statements.
Accounting for Government Grants Received by Business Entities
In December 2025, the FASB issued ASU 2025-10, Government Grants (Topic 832) – Accounting for Government Grants Received by Business Entities. The ASU adds guidance to ASC 832 on the recognition, measurement, and presentation of government grants. The guidance will be effective for annual reporting periods beginning after December 15, 2028, and interim reporting periods within those annual reporting periods. Early adoption is permitted. The standard updates are to be applied using either a modified prospective, modified retrospective, or full retrospective approach, as detailed in the ASU. The Company is currently evaluating the impact of adoption of the standard update on its consolidated financial statements.
32
Targeted Improvements to the Accounting for Internal-Use Software
In September 2025, the FASB issued ASU 2025-06, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Targeted Improvements to the Accounting for Internal-Use Software. The standard update modernizes accounting for internal-use software by eliminating references to project stages and clarifying the threshold to begin capitalizing costs. The standard update also specifies that the disclosure requirements under ASC 360, Property, Plant and Equipment, apply to capitalized software costs accounted under ASC 350-40. The guidance will be effective for annual reporting periods beginning after December 15, 2027, and interim reporting periods within those annual reporting periods. Early adoption is permitted. The standard updates are to be applied using either a prospective, retrospective, or modified transition approach. The Company is currently evaluating the impact of adoption of the standard update on its consolidated financial statements.
Disaggregation of Income Statement Expenses
In November 2024, the FASB issued ASU 2024-03, Income Statement Reporting – Comprehensive
Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard update improves the disclosures about a public business entity’s expenses by requiring more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation and amortization) included within income statement expense captions. The guidance will be effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The standard updates are to be applied prospectively with the option for retrospective application. The Company is currently evaluating the impact of adoption of the standard update on its consolidated financial statements disclosures.
SUMMARY OF QUARTERLY RESULTS
| For the quarter ended millions of dollars |
Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | ||||||||||||||||||||||||
| (except per share amounts) | 2026 | 2026 | 2025 | 2025 | 2025 | 2025 | 2024 | 2024 | ||||||||||||||||||||||||
| Operating revenues |
$ | 2,011 | $ | 2,813 | $ | 2,006 | $ | 2,106 | $ | 1,988 | $ | 2,676 | $ | 1,763 | $ | 1,802 | ||||||||||||||||
| Net income attributable to common shareholders | $ | 105 | $ | 562 | $ | 68 | $ | 228 | $ | 135 | $ | 583 | $ | 154 | $ | 4 | ||||||||||||||||
| EPS – basic |
$ | 0.34 | $ | 1.85 | $ | 0.23 | $ | 0.76 | $ | 0.45 | $ | 1.96 | $ | 0.52 | $ | 0.01 | ||||||||||||||||
| EPS – diluted |
$ | 0.34 | $ | 1.85 | $ | 0.25 | $ | 0.76 | $ | 0.45 | $ | 1.96 | $ | 0.52 | $ | 0.01 | ||||||||||||||||
Quarterly operating revenues and adjusted net income are affected by seasonality. The first quarter provides strong earnings contributions due to a significant portion of the Company’s operations being in northeastern North America, where winter is the peak electricity usage season. The third quarter provides strong earnings contributions due to summer being the heaviest electric consumption season in Florida. Seasonal and other weather patterns, as well as the number and severity of storms, can affect demand for energy and the cost of service. Quarterly results could also be affected by items outlined in the “Significant Items Affecting Earnings” section. Quarter-over-quarter variances are discussed further below.
33
Q2 2026 compared to Q2 2025
For explanation of variances, refer to the “Consolidated Income Statement Highlights” section.
Q1 2026 compared to Q1 2025
For Q1 2026 net income attributable to common shareholders, compared to Q1 2025, decreased by $21 million due to decreased MTM gains, decreased earnings at NSPI, the impact of a stronger CAD and increased Corporate costs. These were partially offset by increased earnings at EES, PGS and TEC. The change in EPS was also impacted by an increase in weighted average shares outstanding.
Q4 2025 compared to Q4 2024
For Q4 2025, net income attributable to common shareholders, compared to Q4 2024, decreased $86 million due to decreased earnings at NSPI and NMGC; increased Corporate costs; and Q4 2024 tax benefit related to a specific financing structure and its wind-up and the tax benefit related to the incremental gain on sale of Emera’s interest in the Labrador Island Link. These were partially offset by decreased MTM losses; increased earnings at EES; and Q4 2024 charges related to wind-down costs for certain asset impairments. The change in EPS was also impacted by an increase in weighted average shares outstanding.
Q3 2025 compared to Q3 2024
For Q3 2025, net income attributable to common shareholders, compared to Q3 2024, increased $224 million primarily due to charges related to the pending sale of NMGC recognized in Q3 2024; and increased earnings at TEC. These were partially offset by increased MTM losses; lower earnings at NSPI and NMGC; and higher Corporate costs. The change in EPS was also impacted by an increase in weighted average shares outstanding.
34
Exhibit 99.2
EMERA INCORPORATED
Unaudited Condensed Consolidated
Interim Financial Statements
June 30, 2026 and 2025
1
Emera Incorporated
Condensed Consolidated Statements of Income (Unaudited)
| Three months ended | Six months ended | |||||||||||||||
| For the |
June 30 | June 30 | ||||||||||||||
| millions of dollars (except per share amounts) |
2026 | 2025 | 2026 | 2025 | ||||||||||||
| Operating revenues |
||||||||||||||||
| Regulated electric |
$ | 1,773 | $ | 1,738 | $ | 3,609 | $ | 3,398 | ||||||||
| Regulated gas |
369 | 351 | 937 | 956 | ||||||||||||
| Non-regulated |
(131) | (101) | 278 | 310 | ||||||||||||
| Total operating revenues (note 5) |
2,011 | 1,988 | 4,824 | 4,664 | ||||||||||||
| Operating expenses |
||||||||||||||||
| Regulated fuel for generation and purchased power |
539 | 531 | 1,181 | 1,106 | ||||||||||||
| Regulated cost of natural gas |
59 | 73 | 214 | 293 | ||||||||||||
| Operating, maintenance and general expenses (“OM&G”) |
590 | 577 | 1,194 | 1,095 | ||||||||||||
| Provincial, state and municipal taxes |
133 | 121 | 263 | 240 | ||||||||||||
| Depreciation and amortization |
336 | 316 | 675 | 635 | ||||||||||||
| Impairment charge (note 3) |
- | 75 | - | 75 | ||||||||||||
| Total operating expenses |
1,657 | 1,693 | 3,527 | 3,444 | ||||||||||||
| Income from operations |
354 | 295 | 1,297 | 1,220 | ||||||||||||
| Income from equity investments (note 7) |
32 | 14 | 53 | 33 | ||||||||||||
| Other (expense) income, net (note 8) |
(12) | 85 | 6 | 116 | ||||||||||||
| Interest expense, net |
275 | 249 | 546 | 504 | ||||||||||||
| Income before provision for income taxes |
99 | 145 | 810 | 865 | ||||||||||||
| Income tax (recovery) expense (note 9) |
(25) | (9) | 104 | 110 | ||||||||||||
| Net income |
124 | 154 | 706 | 755 | ||||||||||||
| Preferred stock dividends |
19 | 19 | 39 | 37 | ||||||||||||
| Net income attributable to common shareholders |
$ | 105 | $ | 135 | $ | 667 | $ | 718 | ||||||||
| Weighted average shares of common stock outstanding (in millions) (note 11) |
||||||||||||||||
| Basic |
306.4 | 298.6 | 304.9 | 297.8 | ||||||||||||
| Diluted |
307.4 | 299.1 | 305.9 | 298.2 | ||||||||||||
| Earnings per common share (note 11) |
||||||||||||||||
| Basic |
$ | 0.34 | $ | 0.45 | $ | 2.19 | $ | 2.41 | ||||||||
| Diluted |
$ | 0.34 | $ | 0.45 | $ | 2.18 | $ | 2.41 | ||||||||
| Dividends per common share declared |
$ | 0.7325 | $ | 0.7250 | $ | 1.4650 | $ | 1.4500 | ||||||||
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 | Six months ended | |||||||||||||||
| For the |
June 30 | June 30 | ||||||||||||||
| millions of dollars |
2026 | 2025 | 2026 | 2025 | ||||||||||||
| Net income |
$ | 124 | $ | 154 | $ | 706 | $ | 755 | ||||||||
| Other comprehensive income (loss) (“OCI”), net of tax |
||||||||||||||||
| Foreign currency translation adjustment (1) |
233 | (673) | 463 | (685) | ||||||||||||
| Unrealized (losses) gains on net investment hedges (2) |
(21) | 87 | (49) | 89 | ||||||||||||
| Cash flow hedges – net of reclassification adjustment for gains included in income |
(1) | (1) | (1) | (1) | ||||||||||||
| Unrealized losses on available-for-sale investment |
- | - | (1) | - | ||||||||||||
| Net change in unrecognized pension and post-retirement benefit obligation |
- | - | (5) | (4) | ||||||||||||
| OCI (1) |
$ | 211 | $ | (587) | $ | 407 | $ | (601) | ||||||||
| Comprehensive income (loss) of Emera Incorporated |
$ | 335 | $ | (433) | $ | 1,113 | $ | 154 | ||||||||
(1) Net of tax expense of $2 million (2025 – $9 million recovery) for the three months ended June 30, 2026 and tax expense of $2 million (2025 – $9 million recovery) for the six months ended June 30, 2026.
(2) As of June 30, 2026, the Company had $750 million United States dollar (“USD”) denominated hybrid notes (2025 – $1.2 billion USD) designated as a hedge of the foreign currency exposure of its net investment in USD denominated operations. Refer to note 14.
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
3
Emera Incorporated
Condensed Consolidated Balance Sheets (Unaudited)
| As at |
June 30 | December 31 | ||||||
| millions of dollars |
2026 | 2025 | ||||||
| Assets |
||||||||
| Current assets |
||||||||
| Cash and cash equivalents |
$ | 396 | $ | 349 | ||||
| Restricted cash |
11 | 16 | ||||||
| Inventory |
823 | 821 | ||||||
| Derivative instruments (notes 13 and 14) |
234 | 156 | ||||||
| Regulatory assets (note 6) |
225 | 409 | ||||||
| Receivables and other current assets (note 16) |
2,347 | 2,439 | ||||||
| Assets held for sale (note 3) |
145 | 199 | ||||||
| 4,181 | 4,389 | |||||||
| Property, plant and equipment (“PP&E”), net of accumulated depreciation and amortization of $11,228 and $10,845, respectively |
28,949 | 27,408 | ||||||
| Other assets |
||||||||
| Deferred income taxes (note 9) |
392 | 421 | ||||||
| Derivative instruments (notes 13 and 14) |
35 | 42 | ||||||
| Regulatory assets (note 6) |
2,873 | 2,789 | ||||||
| Net investment in direct finance and sales type leases |
563 | 572 | ||||||
| Investments subject to significant influence (note 7) |
632 | 634 | ||||||
| Goodwill |
5,785 | 5,580 | ||||||
| Other long-term assets (note 23) |
958 | 894 | ||||||
| Assets held for sale (note 3) |
2,188 | 2,088 | ||||||
| 13,426 | 13,020 | |||||||
| Total assets |
$ | 46,556 | $ | 44,817 |
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
4
Emera Incorporated
Condensed Consolidated Balance Sheets (Unaudited) – Continued
| As at |
June 30 | December 31 | ||||||
| millions of dollars |
2026 | 2025 | ||||||
| Liabilities and Equity |
||||||||
| Current liabilities |
||||||||
| Short-term debt (note 18) |
$ | 2,530 | $ | 1,807 | ||||
| Current portion of long-term debt (note 19) |
44 | 1,201 | ||||||
| Accounts payable |
1,690 | 1,948 | ||||||
| Derivative instruments (notes 13 and 14) |
509 | 534 | ||||||
| Regulatory liabilities (note 6) |
198 | 211 | ||||||
| Other current liabilities |
607 | 535 | ||||||
| Liabilities associated with assets held for sale (note 3) |
145 | 391 | ||||||
| 5,723 | 6,627 | |||||||
| Long-term liabilities |
||||||||
| Long-term debt (note 19) |
19,543 | 18,453 | ||||||
| Deferred income taxes (note 9) |
2,656 | 2,516 | ||||||
| Derivative instruments (notes 13 and 14) |
168 | 115 | ||||||
| Regulatory liabilities (note 6) |
1,546 | 1,458 | ||||||
| Pension and post-retirement liabilities |
266 | 268 | ||||||
| Other long-term liabilities |
993 | 960 | ||||||
| Liabilities associated with assets held for sale (note 3) |
1,287 | 1,024 | ||||||
| 26,459 | 24,794 | |||||||
| Equity |
||||||||
| Common stock (note 10) |
9,750 | 9,387 | ||||||
| Cumulative preferred stock (note 21) |
1,422 | 1,422 | ||||||
| Contributed surplus |
87 | 86 | ||||||
| Accumulated other comprehensive income (“AOCI”) (note 12) |
1,280 | 873 | ||||||
| Retained earnings |
1,835 | 1,614 | ||||||
| Total Emera Incorporated equity |
14,374 | 13,382 | ||||||
| Non-controlling interest in subsidiaries (“NCI”) |
- | 14 | ||||||
| Total equity |
14,374 | 13,396 | ||||||
| Total liabilities and equity |
$ | 46,556 | $ | 44,817 | ||||
| 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 | Six months ended June 30 | |||||||
| millions of dollars | 2026 | 2025 | ||||||
| Operating activities | ||||||||
| Net income | $ | 706 | $ | 755 | ||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
| Depreciation and amortization |
672 | 639 | ||||||
| Income from equity investments, net of dividends |
(21) | 5 | ||||||
| Allowance for funds used during construction (“AFUDC”) – equity |
(25) | (37) | ||||||
| Deferred income taxes, net |
84 | 120 | ||||||
| Net change in pension and post-retirement liabilities |
(17) | (22) | ||||||
| Nova Scotia Power Inc. (“NSPI”) fuel adjustment mechanism (“FAM”) |
(35) | (91) | ||||||
| Net change in fair value (“FV”) of derivative instruments |
(31) | (251) | ||||||
| Net change in regulatory assets and liabilities |
144 | 82 | ||||||
| Net change in capitalized transportation capacity |
(86) | (10) | ||||||
| Impairment charge |
- | 75 | ||||||
| Loss on sale of Grand Bahama Power Company Limited (“GBPC”), excluding transaction costs |
20 | - | ||||||
| Other operating activities, net |
- | 41 | ||||||
| Changes in non-cash working capital (note 22) |
(9) | (507) | ||||||
| Net cash provided by operating activities |
1,402 | 799 | ||||||
| Investing activities |
||||||||
| Additions to PP&E |
(1,756) | (1,720) | ||||||
| Proceeds on disposal of assets |
9 | 45 | ||||||
| Proceeds from disposition (note 3) |
219 | - | ||||||
| Other investing activities |
(3) | 3 | ||||||
| Net cash used in investing activities |
(1,531) | (1,672) | ||||||
| Financing activities |
||||||||
| Change in short-term debt, net |
488 | (301) | ||||||
| Proceeds from short-term debt with maturities greater than 90 days |
- | 500 | ||||||
| Proceeds from long-term debt, net of issuance costs |
2,625 | 907 | ||||||
| Retirement of long-term debt |
(2,838) | (162) | ||||||
| Net (repayments) proceeds under committed credit facilities |
(45) | 218 | ||||||
| Issuance of common stock, net of issuance costs |
217 | 30 | ||||||
| Dividends on common stock |
(304) | (278) | ||||||
| Dividends on preferred stock |
(39) | (37) | ||||||
| Other financing activities |
(9) | - | ||||||
| Net cash provided by financing activities |
95 | 877 | ||||||
| Effect of exchange rate changes on cash, cash equivalents, restricted cash and cash associated with assets held for sale | 74 | (7) | ||||||
| Net increase (decrease) in cash, cash equivalents, restricted cash, and cash associated with assets held for sale | 40 | (3) | ||||||
| Cash, cash equivalents, restricted cash and cash associated with assets held for sale, beginning of period | 371 | 221 | ||||||
| Cash, cash equivalents, restricted cash and cash associated with assets held for sale, end of period |
$ | 411 | $ | 218 | ||||
| Cash, cash equivalents, restricted cash and cash associated with assets held for sale consists of: | ||||||||
| Cash |
$ | 388 | $ | 195 | ||||
| Short-term investments |
8 | 5 | ||||||
| Restricted cash |
11 | 14 | ||||||
| Cash associated with assets held for sale |
4 | 4 | ||||||
| Total |
$ | 411 | $ | 218 | ||||
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 June 30, 2026 |
| |||||||||||||||||||||||||||
| Balance, March 31, 2026 |
$ | 9,658 | $ | 1,422 | $ | 87 | $ | 1,069 | $ | 1,954 | $ | 14 | $ | 14,204 | ||||||||||||||
| Net income of Emera Incorporated |
- | - | - | - | 124 | - | 124 | |||||||||||||||||||||
| OCI, net of tax expense of $2 million |
- | - | - | 211 | - | - | 211 | |||||||||||||||||||||
| Dividends declared on preferred stock (1) |
- | - | - | - | (19) | - | (19) | |||||||||||||||||||||
| Dividends declared on common stock ($0.7325/share) |
- | - | - | - | (224) | - | (224) | |||||||||||||||||||||
| Issued under the Dividend Reinvestment Program (“DRIP”), net of discounts | 70 | - | - | - | - | - | 70 | |||||||||||||||||||||
| Senior management stock options exercised and Employee Common Share Purchase Plan (“ECSPP”) | 22 | - | - | - | - | - | 22 | |||||||||||||||||||||
| Sale of GBPC and associated preferred shares |
- | - | - | - | - | (14) | (14) | |||||||||||||||||||||
| Balance, June 30, 2026 |
$ | 9,750 | $ | 1,422 | $ | 87 | $ | 1,280 | $ | 1,835 | $ | - | $ | 14,374 | ||||||||||||||
| For the six months ended June 30, 2026 |
| |||||||||||||||||||||||||||
| Balance, December 31, 2025 |
$ | 9,387 | $ | 1,422 | $ | 86 | $ | 873 | $ | 1,614 | $ | 14 | $ | 13,396 | ||||||||||||||
| Net income of Emera Incorporated | - | - | - | - | 706 | - | 706 | |||||||||||||||||||||
| OCI, net of tax expense of $2 million | - | - | - | 407 | - | - | 407 | |||||||||||||||||||||
| Dividends declared on preferred stock (2) | - | - | - | - | (39) | - | (39) | |||||||||||||||||||||
| Dividends declared on common stock ($1.4650/share) | - | - | - | - | (446) | - | (446) | |||||||||||||||||||||
| Issued under the DRIP, net of discounts | 141 | - | - | - | - | - | 141 | |||||||||||||||||||||
| Issuance of common stock under the at-the-market (“ATM”) program, net of after-tax issuance costs | 184 | - | - | - | - | - | 184 | |||||||||||||||||||||
| Senior management stock options exercised and ECSPP | 38 | - | 1 | - | - | - | 39 | |||||||||||||||||||||
| Sale of GBPC and associated preferred shares | - | - | - | - | - | (14) | (14) | |||||||||||||||||||||
| Balance, June 30, 2026 |
$ | 9,750 | $ | 1,422 | $ | 87 | $ | 1,280 | $ | 1,835 | $ | - | $ | 14,374 | ||||||||||||||
(1) Series A; $0.3094/share, Series C; $0.4021/share, Series E; $0.2813/share, Series F; $0.3593/share; Series H; $0.3953/share; Series J; $0.3966/share and Series L; $0.2875/share
(2) Series A; $0.6188/share, Series C; $0.8043/share, Series E; $0.5625/share, Series F; $0.7186/share; Series H; $0.7905/share; Series J; $0.6622/share and Series L; $0.5750/share
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
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 June 30, 2025 | ||||||||||||||||||||||||||
| Balance, March 31, 2025 |
$ | 9,140 | $ | 1,422 | $ | 84 | $ | 1,247 | $ | 1,836 | $ | 14 | $ 13,743 | |||||||||||||
| Net income of Emera Incorporated |
- | - | - | - | 154 | - | 154 | |||||||||||||||||||
| OCI, net of tax recovery of $9 million |
- | - | - | (587) | - | - | (587) | |||||||||||||||||||
| Dividends declared on preferred stock (1) |
- | - | - | - | (19) | - | (19) | |||||||||||||||||||
| Dividends declared on common stock ($0.7250/share) |
- | - | - | - | (216) | - | (216) | |||||||||||||||||||
| Issued under the DRIP, net of discounts |
77 | - | - | - | - | - | 77 | |||||||||||||||||||
| Senior management stock options exercised and ECSPP |
11 | - | 1 | - | - | - | 12 | |||||||||||||||||||
| Balance, June 30, 2025 |
$ | 9,228 | $ | 1,422 | $ | 85 | $ | 660 | $ | 1,755 | $ | 14 | $ 13,164 | |||||||||||||
| For the six months ended June 30, 2025 | ||||||||||||||||||||||||||
| Balance, December 31, 2024 |
$ | 9,042 | $ | 1,422 | $ | 84 | $ | 1,261 | $ | 1,468 | $ | 14 | $ 13,291 | |||||||||||||
| Net income of Emera Incorporated |
- | - | - | - | 755 | - | 755 | |||||||||||||||||||
| OCI, net of tax recovery of $9 million |
- | - | - | (601) | - | - | (601) | |||||||||||||||||||
| Dividends declared on preferred stock (2) |
- | - | - | - | (37) | - | (37) | |||||||||||||||||||
| Dividends declared on common stock ($1.4500/share) |
- | - | - | - | (431) | - | (431) | |||||||||||||||||||
| Issued under the DRIP, net of discount |
153 | - | - | - | - | - | 153 | |||||||||||||||||||
| Issuance under ATM program, net of after-tax issuance costs | 10 | - | - | - | - | - | 10 | |||||||||||||||||||
| Senior management stock options exercised and ECSPP |
23 | - | 1 | - | - | - | 24 | |||||||||||||||||||
| Balance, June 30, 2025 |
$ | 9,228 | $ | 1,422 | $ | 85 | $ | 660 | $ | 1,755 | $ | 14 | $ 13,164 | |||||||||||||
(1) Series A; $0.1364/share, Series B; $0.3032/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; $0.2728/share, Series B; $0.6662/share, Series C; $0.8043/share, Series E; $0.5625/share, Series F; $0.6219/share; Series H; $0.7905/share; Series J; $0.5313/share and Series L; $0.5750/share
The accompanying notes are an integral part of these condensed consolidated interim financial statements.
8
Emera Incorporated
Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)
As at June 30, 2026 and 2025
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
Emera Incorporated (“Emera” or the “Company”) is an energy and services company that invests in electricity generation, transmission and distribution, and gas transmission and distribution. At June 30, 2026, Emera’s reportable segments include the following:
| • | Florida Electric Utility, which consists of Tampa Electric (“TEC”), a vertically integrated regulated electric utility in West Central Florida. |
| • | Canadian Electric Utilities, which includes: |
| • | NSPI, a vertically integrated regulated electric utility and the primary electricity supplier in Nova Scotia; |
| • | a 100 per cent equity interest in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link Project, a $1.8 billion, including AFUDC, transmission project between the island of Newfoundland and Nova Scotia; and |
| • | a 50 per cent indirect voting equity interest in Wasoqonatl Transmission Incorporated (“WTI”), a transmission line project to create a reliability intertie between Nova Scotia and New Brunswick. |
| • | Gas Utilities and Infrastructure, which includes: |
| • | Peoples Gas System, Inc. (“PGS”), a regulated gas distribution utility operating across Florida; |
| • | New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility serving customers in New Mexico. On August 5, 2024, Emera announced an agreement to sell NMGC. On July 30, 2026, the New Mexico Public Regulation Commission (“NMPRC”) issued a final order approving the transaction. 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; 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. |
On May 12, 2026, Emera completed the sale of GBPC which was previously included in the Other Electric Utilities segment. For further details, refer to note 3.
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 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a 660 MW pumped storage hydroelectric facility in northwestern Massachusetts. |
| • | Emera US Finance LP, Emera US Finance, LLC (“Emera Finance”), EUSHI Finance, Inc. (“EUSHI Finance”) and TECO Finance, Inc., financing subsidiaries of Emera; |
| • | Emera US Holdings Inc. (“EUSHI”), a wholly owned holding company for certain of Emera’s assets located in the US; and |
| • | Other investments. |
Basis of Presentation
These unaudited condensed consolidated interim financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”). The significant accounting policies applied to these unaudited condensed consolidated interim financial statements are consistent with those disclosed in the audited consolidated financial statements as at and for the year ended December 31, 2025.
In the opinion of management, these unaudited condensed consolidated interim financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 2026.
All dollar amounts are presented in Canadian dollars, unless otherwise indicated.
Use of Management Estimates
The preparation of unaudited condensed consolidated interim financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during reporting periods. Significant areas requiring use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations, and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. There were no material changes in the nature of the Company’s critical accounting estimates from those disclosed in Emera’s 2025 annual audited consolidated financial statements.
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 information technology (“IT”) network and servers supporting portions of its business applications. There was no disruption to the Canadian physical operations or to Emera’s US or Caribbean utilities’ operations.
The Company implemented business continuity processes for certain impacted business and administrative functions at its Canadian affiliates. The systematic restoration of affected IT systems and corresponding transition away from business continuity processes is substantially complete. The Company maintains cyber insurance coverage and is working with its insurer on the claims process.
2. FUTURE ACCOUNTING PRONOUNCEMENTS
The Company considers the applicability and impact of all Accounting Standard Updates (“ASU”) issued by the Financial Accounting Standards Board (“FASB”). The following updates have been issued by the FASB but, as allowed, have not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be either not applicable to the Company or to have an insignificant impact on the consolidated financial statements.
Accounting for Environmental Credits and Environmental Credit Obligations
In May 2026, the FASB issued ASU 2026-02, Environmental Credits and Environmental Credit Obligations (Topic 818). This ASU establishes new guidance for the recognition, measurement, presentation, and disclosure of environmental credits (such as renewable energy credits, carbon offsets, and similar instruments) and environmental credit obligations. The ASU is effective for fiscal years beginning after December 15, 2027, and interim periods within those fiscal years. Early adoption is permitted. An entity must apply the guidance retrospectively through a cumulative-effect adjustment to retained earnings. The Company is currently evaluating the impact of adoption of the standard update on its consolidated financial statements.
Accounting for Government Grants Received by Business Entities
In December 2025, the FASB issued ASU 2025-10, Government Grants (Topic 832) – Accounting for Government Grants Received by Business Entities. The ASU adds guidance to ASC 832 on the recognition, measurement, and presentation of government grants. The guidance will be effective for annual reporting periods beginning after December 15, 2028, and interim reporting periods within those annual reporting periods. Early adoption is permitted. The standard updates are to be applied using either a modified prospective, modified retrospective, or full retrospective approach, as detailed in the ASU. The Company is currently evaluating the impact of adoption of the standard update on its consolidated financial statements.
11
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.
3. DISPOSITIONS
Sale of GBPC
On May 12, 2026, Emera completed the sale of its 100 per cent interest in GBPC. As a result of the sale, Emera recognized a loss of $21 million after transaction costs ($19 million, after tax and transaction costs). This was recorded in “Other (expense) income, net” on the Condensed Consolidated Statements of Income and included in the “Other Electric Utilities” and “Other” segments.
Pending Sale of NMGC
On August 5, 2024, Emera entered into an agreement to sell its indirect wholly-owned subsidiary NMGC for a total enterprise value of approximately $1.3 billion USD, consisting of cash proceeds and the transfer of debt and customary closing adjustments. On July 30, 2026, the NMPRC issued a final order approving the transaction. On July 31, 2026, certain of the intervening parties filed a notice of appeal of the final order to the New Mexico Supreme Court. There have been no further steps taken in the appeal process to date.
As a result of the pending sale, NMGC’s assets and liabilities were classified as held for sale beginning Q3 2024 and the carrying value of the assets and liabilities were adjusted to FV less cost to sell. At each reporting date, the Company performs an assessment of the FV of the disposal group by comparing the FV of expected transaction proceeds, less costs to sell, to the carrying value of net assets, including goodwill. There were no impairment or FV less costs to sell adjustments recorded in 2026.
12
On June 30, 2025, the Company remeasured the NMGC disposal group at the lower of its carrying value amount and FV less costs to sell by comparing the FV of expected transaction proceeds to the carrying value of net assets. As a result of the change in the expected timing of the transaction close, a non-cash impairment charge of $75 million ($71 million, after-tax) or $55 million USD ($52 million USD, after-tax) was recorded in “Impairment charge” on the Condensed Consolidated Statements of Income in Q2 2025.
An additional loss for estimated future transaction costs of $2 million ($1 million after-tax) was recorded in “Other (expense) income, net” on the Condensed Consolidated Statements of Income in Q2 2025.
The Company will continue to record depreciation on the NMGC assets through the transaction closing date, as the depreciation continues to be reflected in customer rates and will be reflected in the carryover basis of the assets when sold. Depreciation and amortization of $134 million ($97 million USD) was recorded on these assets from August 5, 2024, the date they were classified as held for sale, through June 30, 2026. Of the $134 million ($97 million USD) recorded to date, $37 million ($27 million USD) was recorded in 2026.
Details of the assets and liabilities classified as held for sale are as follows:
| As at millions of dollars |
June 30 2026 |
December 31 2025 | ||||
| Cash and cash equivalents |
$ | 4 | $ 6 | |||
| Inventory |
6 | 10 | ||||
| Derivative instruments |
17 | - | ||||
| Regulatory assets |
53 | 41 | ||||
| Receivables and other current assets |
65 | 142 | ||||
| Current assets held for sale |
$ | 145 | $ 199 | |||
| PP&E |
1,956 | 1,856 | ||||
| Regulatory assets |
4 | 4 | ||||
| Goodwill |
299 | 289 | ||||
| Other long-term assets |
20 | 28 | ||||
| Less: Adjustment to FV less costs to sell |
(91) | (89) | ||||
| Long-term assets held for sale |
$ | 2,188 | $ 2,088 | |||
| Total assets held for sale |
$ | 2,333 | $ 2,287 | |||
| Short-term debt |
$ | 26 | $ 116 | |||
| Current portion of long-term debt |
- | 96 | ||||
| Regulatory liabilities |
25 | 25 | ||||
| Accounts payable and other current liabilities |
94 | 154 | ||||
| Current liabilities associated with assets held for sale |
145 | 391 | ||||
| Long-term debt |
786 | 567 | ||||
| Deferred income taxes |
224 | 185 | ||||
| Regulatory liabilities |
269 | 261 | ||||
| Other long-term liabilities |
8 | 11 | ||||
| Long-term liabilities associated with assets held for sale |
$ | 1,287 | $ 1,024 | |||
| Total liabilities associated with assets held for sale |
$ | 1,432 | $ 1,415 | |||
4. SEGMENT INFORMATION
Emera manages its reportable segments separately due in part to their different operating, regulatory and geographical environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets, as reported to the Company’s chief operating decision maker (“CODM”). Emera’s CODM is the Chief Executive Officer.
13
| 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 June 30, 2026 | ||||||||||||||||||||||||||
| Operating revenues from external customers (1) | $ | 1,191 | $ | 448 | $ | 375 | $ | 133 | $ | (136) | $ | - | $ 2,011 | |||||||||||||
| Inter-segment revenues (1) | 3 | - | 5 | - | 12 | (20) | - | |||||||||||||||||||
| Total operating revenues |
1,194 | 448 | 380 | 133 | (124) | (20) | 2,011 | |||||||||||||||||||
| Regulated fuel for generation and purchased power | 251 | 215 | - | 79 | - | (6) | 539 | |||||||||||||||||||
| Regulated cost of natural gas | - | - | 59 | - | - | - | 59 | |||||||||||||||||||
| OM&G | 298 | 109 | 131 | 31 | 32 | (11) | 590 | |||||||||||||||||||
| Provincial, state and municipal taxes | 89 | 13 | 30 | 1 | - | - | 133 | |||||||||||||||||||
| Depreciation and amortization | 189 | 75 | 55 | 15 | 2 | - | 336 | |||||||||||||||||||
| Income from equity investments | - | 10 | 5 | 1 | 16 | - | 32 | |||||||||||||||||||
| Other (expense) income, net | 18 | 6 | 3 | (14) | (28) | 3 | (12) | |||||||||||||||||||
| Interest expense, net (2) | 82 | 38 | 39 | 4 | 112 | - | 275 | |||||||||||||||||||
| Income tax expense (recovery) | 42 | (2) | 19 | - | (84) | - | (25) | |||||||||||||||||||
| Preferred stock dividends | - | - | - | - | 19 | - | 19 | |||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 261 | $ | 16 | $ | 55 | $ | (10) | $ | (217) | $ | - | $ 105 | |||||||||||||
| For the six months ended June 30, 2026 | ||||||||||||||||||||||||||
| Operating revenues from external customers (1) | $ | 2,289 | $ | 1,060 | $ | 948 | $ | 260 | $ | 267 | $ | - | $ 4,824 | |||||||||||||
| Inter-segment revenues (1) | 5 | - | 10 | - | 17 | (32) | - | |||||||||||||||||||
| Total operating revenues |
2,294 | 1,060 | 958 | 260 | 284 | (32) | 4,824 | |||||||||||||||||||
| Regulated fuel for generation and purchased power | 544 | 508 | - | 140 | - | (11) | 1,181 | |||||||||||||||||||
| Regulated cost of natural gas | - | - | 214 | - | - | - | 214 | |||||||||||||||||||
| OM&G | 569 | 238 | 251 | 65 | 92 | (21) | 1,194 | |||||||||||||||||||
| Provincial, state and municipal taxes | 170 | 25 | 66 | 2 | - | - | 263 | |||||||||||||||||||
| Depreciation and amortization | 373 | 154 | 108 | 36 | 4 | - | 675 | |||||||||||||||||||
| Income from equity investments | - | 22 | 10 | 2 | 19 | - | 53 | |||||||||||||||||||
| Other income (expense), net | 35 | 12 | 6 | (13) | (34) | - | 6 | |||||||||||||||||||
| Interest expense, net (2) | 163 | 82 | 76 | 9 | 216 | - | 546 | |||||||||||||||||||
| Income tax expense (recovery) | 69 | (15) | 68 | - | (18) | - | 104 | |||||||||||||||||||
| Preferred stock dividends | - | - | - | - | 39 | - | 39 | |||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 441 | $ | 102 | $ | 191 | $ | (3) | $ | (64) | $ | - | $ 667 | |||||||||||||
| As at June 30, 2026 | ||||||||||||||||||||||||||
| Total assets | $ | 26,770 | $ | 8,853 | $ | 8,998 | $ | 1,012 | $ | 2,149 | $ | (1,226) | $ 46,556 | |||||||||||||
| Investments subject to significant influence | $ | - | $ | 465 | $ | 110 | $ | 57 | $ | - | $ | - | $ 632 | |||||||||||||
| Goodwill | $ | 4,972 | $ | - | $ | 813 | $ | - | $ | - | $ | - | $ 5,785 | |||||||||||||
(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 $7 million for the three months ended June 30, 2026, and $13 million for the six months ended June 30, 2026 between the Gas Utilities and Infrastructure and Other segments.
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 June 30, 2025 | ||||||||||||||||||||||||||
| Operating revenues from external customers (1) | $ | 1,157 | $ | 436 | $ | 357 | $ | 145 | $ | (107) | $ | - | $ 1,988 | |||||||||||||
| Inter-segment revenues (1) | 3 | - | 4 | - | 4 | (11) | - | |||||||||||||||||||
| Total operating revenues |
1,160 | 436 | 361 | 145 | (103) | (11) | 1,988 | |||||||||||||||||||
| Regulated fuel for generation and purchased power | 259 | 202 | - | 72 | - | (2) | 531 | |||||||||||||||||||
| Regulated cost of natural gas | - | - | 73 | - | - | - | 73 | |||||||||||||||||||
| OM&G | 294 | 109 | 114 | 38 | 30 | (8) | 577 | |||||||||||||||||||
| Provincial, state and municipal taxes | 81 | 13 | 26 | 1 | - | - | 121 | |||||||||||||||||||
| Depreciation and amortization | 172 | 74 | 49 | 19 | 2 | - | 316 | |||||||||||||||||||
| Income from equity investments | - | 11 | 4 | 1 | (2) | - | 14 | |||||||||||||||||||
| Other income, net | 24 | 7 | 1 | 3 | 49 | 1 | 85 | |||||||||||||||||||
| Interest expense, net (2) | 73 | 43 | 38 | 5 | 90 | - | 249 | |||||||||||||||||||
| Impairment charge | - | - | - | - | 75 | - | 75 | |||||||||||||||||||
| Income tax expense (recovery) | 45 | (4) | 18 | - | (68) | - | (9) | |||||||||||||||||||
| Preferred stock dividends | - | - | - | - | 19 | - | 19 | |||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 260 | $ | 17 | $ | 48 | $ | 14 | $ | (204) | $ | - | $ 135 | |||||||||||||
| For the six months ended June 30, 2025 | ||||||||||||||||||||||||||
| Operating revenues from external customers (1) | $ | 2,087 | $ | 1,035 | $ | 968 | $ | 276 | $ | 298 | $ | - | $ 4,664 | |||||||||||||
| Inter-segment revenues (1) | 5 | - | 8 | - | 16 | (29) | - | |||||||||||||||||||
| Total operating revenues |
2,092 | 1,035 | 976 | 276 | 314 | (29) | 4,664 | |||||||||||||||||||
| Regulated fuel for generation and purchased power | 491 | 482 | - | 140 | - | (7) | 1,106 | |||||||||||||||||||
| Regulated cost of natural gas | - | - | 293 | - | - | - | 293 | |||||||||||||||||||
| OM&G | 506 | 229 | 237 | 74 | 65 | (16) | 1,095 | |||||||||||||||||||
| Provincial, state and municipal taxes | 153 | 25 | 60 | 2 | - | - | 240 | |||||||||||||||||||
| Depreciation and amortization | 347 | 147 | 100 | 37 | 4 | - | 635 | |||||||||||||||||||
| Income from equity investments | - | 22 | 10 | 2 | (1) | - | 33 | |||||||||||||||||||
| Other income, net | 47 | 14 | 6 | 2 | 41 | 6 | 116 | |||||||||||||||||||
| Interest expense, net (2) | 147 | 84 | 75 | 10 | 188 | - | 504 | |||||||||||||||||||
| Impairment charge | - | - | - | - | 75 | - | 75 | |||||||||||||||||||
| Income tax expense (recovery) | 71 | (34) | 59 | 3 | 11 | - | 110 | |||||||||||||||||||
| Preferred stock dividends | - | - | - | - | 37 | - | 37 | |||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 424 | $ | 138 | $ | 168 | $ | 14 | $ | (26) | $ | - | $ 718 | |||||||||||||
| As at December 31, 2025 | ||||||||||||||||||||||||||
| Total assets | $ | 24,636 | $ | 8,546 | $ | 8,476 | $ | 1,439 | $ | 2,469 | $ | (749) | $ 44,817 | |||||||||||||
| Investment subject to significant influence | $ | - | $ | 471 | $ | 108 | $ | 55 | $ | - | $ | - | $ 634 | |||||||||||||
| Goodwill | $ | 4,796 | $ | - | $ | 784 | $ | - | $ | - | $ | - | $ 5,580 | |||||||||||||
(1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E, OM&G, or regulated fuel for generation and purchased power. Inter-company transactions that have not been eliminated are measured at the amount of consideration established 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 June 30, 2025, and $14 million for the six months ended June 30, 2025 between the Gas Utilities and Infrastructure and Other segments.
15
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 June 30, 2026 | ||||||||||||||||||||||||||||||
| Regulated Revenue |
||||||||||||||||||||||||||||||
| Residential |
$ | 673 | $ | 232 | $ | 49 | $ | 148 | $ | - | $ | - | $ 1,102 | |||||||||||||||||
| Commercial |
307 | 129 | 74 | 116 | - | - | 626 | |||||||||||||||||||||||
| Industrial |
70 | 68 | 4 | 24 | - | (4) | 162 | |||||||||||||||||||||||
| Other electric |
154 | 10 | 1 | - | - | - | 165 | |||||||||||||||||||||||
| Regulatory deferrals |
(17) | - | 2 | - | - | - | (15) | |||||||||||||||||||||||
| Other (1) |
7 | 9 | 3 | 71 | - | (3) | 87 | |||||||||||||||||||||||
| Finance income (2)(3) |
- | - | - | 15 | - | - | 15 | |||||||||||||||||||||||
|
| ||||||||||||||||||||||||||||||
| Regulated revenue |
1,194 | 448 | 133 | 374 | - | (7) | 2,142 | |||||||||||||||||||||||
|
| ||||||||||||||||||||||||||||||
| Non-Regulated Revenue |
||||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
- | - | - | - | (28) | - | (28) | |||||||||||||||||||||||
| Other non-regulated operating revenue |
- | - | - | 6 | 8 | (8) | 6 | |||||||||||||||||||||||
| Mark-to-market (3) |
- | - | - | - | (104) | (5) | (109) | |||||||||||||||||||||||
|
| ||||||||||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 6 | (124) | (13) | (131) | |||||||||||||||||||||||
|
| ||||||||||||||||||||||||||||||
| Total operating revenues |
$ | 1,194 | $ | 448 | $ | 133 | $ | 380 | $ | (124) | $ | (20) | $ 2,011 | |||||||||||||||||
|
| ||||||||||||||||||||||||||||||
| For the six months ended June 30, 2026 | ||||||||||||||||||||||||||||||
| Regulated Revenue |
||||||||||||||||||||||||||||||
| Residential |
$ | 1,227 | $ | 602 | $ | 92 | $ | 421 | $ | - | $ | - | $ 2,342 | |||||||||||||||||
| Commercial |
579 | 283 | 140 | 280 | - | - | 1,282 | |||||||||||||||||||||||
| Industrial |
135 | 133 | 10 | 51 | - | (10) | 319 | |||||||||||||||||||||||
| Other electric |
360 | 25 | 3 | - | - | - | 388 | |||||||||||||||||||||||
| Regulatory deferrals |
(19) | - | 9 | - | - | - | (10) | |||||||||||||||||||||||
| Other (1) |
12 | 17 | 6 | 165 | - | (5) | 195 | |||||||||||||||||||||||
| Finance income (2)(3) |
- | - | - | 30 | - | - | 30 | |||||||||||||||||||||||
|
| ||||||||||||||||||||||||||||||
| Regulated revenue |
2,294 | 1,060 | 260 | 947 | - | (15) | 4,546 | |||||||||||||||||||||||
|
| ||||||||||||||||||||||||||||||
| Non-Regulated Revenue |
||||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
- | - | - | - | 155 | - | 155 | |||||||||||||||||||||||
| Other non-regulated operating revenue |
- | - | - | 11 | 22 | (17) | 16 | |||||||||||||||||||||||
| Mark-to-market (3) |
- | - | - | - | 107 | - | 107 | |||||||||||||||||||||||
|
| ||||||||||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 11 | 284 | (17) | 278 | |||||||||||||||||||||||
|
| ||||||||||||||||||||||||||||||
| Total operating revenues |
$ | 2,294 | $ | 1,060 | $ | 260 | $ | 958 | $ | 284 | $ | (32) | $ 4,824 | |||||||||||||||||
|
| ||||||||||||||||||||||||||||||
(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.
16
| 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 June 30, 2025 | ||||||||||||||||||||||||||||||
| Regulated Revenue |
||||||||||||||||||||||||||||||
| Residential |
$ | 639 | $ | 230 | $ | 51 | $ | 138 | $ | - | $ | - | $ 1,058 | |||||||||||||||||
| Commercial |
288 | 120 | 75 | 114 | - | - | 597 | |||||||||||||||||||||||
| Industrial |
68 | 67 | 8 | 24 | - | (4) | 163 | |||||||||||||||||||||||
| Other electric |
151 | 10 | 2 | - | - | - | 163 | |||||||||||||||||||||||
| Regulatory deferrals |
8 | - | 6 | - | - | - | 14 | |||||||||||||||||||||||
| Other (1) |
6 | 9 | 3 | 64 | - | (3) | 79 | |||||||||||||||||||||||
| Finance income (2)(3) |
- | - | - | 15 | - | - | 15 | |||||||||||||||||||||||
| Regulated revenue |
1,160 | 436 | 145 | 355 | - | (7) | 2,089 | |||||||||||||||||||||||
| Non-Regulated Revenue |
||||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
- | - | - | - | (19) | - | (19) | |||||||||||||||||||||||
| Other non-regulated operating revenue |
- | - | - | 6 | 7 | (7) | 6 | |||||||||||||||||||||||
|
Mark-to-market (3) |
- | - | - | - | (91) | 3 | (88) | |||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 6 | (103) | (4) | (101) | |||||||||||||||||||||||
| Total operating revenues |
$ | 1,160 | $ | 436 | $ | 145 | $ | 361 | $ | (103) | $ | (11) | $ 1,988 | |||||||||||||||||
| For the six months ended June 30, 2025 | ||||||||||||||||||||||||||||||
| Regulated Revenue |
||||||||||||||||||||||||||||||
| Residential |
$ | 1,122 | $ | 591 | $ | 93 | $ | 452 | $ | - | $ | - | $ 2,258 | |||||||||||||||||
| Commercial |
535 | 268 | 150 | 292 | - | - | 1,245 | |||||||||||||||||||||||
| Industrial |
134 | 135 | 14 | 50 | - | (8) | 325 | |||||||||||||||||||||||
| Other electric |
267 | 22 | 4 | - | - | - | 293 | |||||||||||||||||||||||
| Regulatory deferrals |
22 | - | 9 | - | - | - | 31 | |||||||||||||||||||||||
| Other (1) |
12 | 19 | 6 | 138 | - | (5) | 170 | |||||||||||||||||||||||
| Finance income (2)(3) |
- | - | - | 32 | - | - | 32 | |||||||||||||||||||||||
| Regulated revenue |
2,092 | 1,035 | 276 | 964 | - | (13) | 4,354 | |||||||||||||||||||||||
| Non-Regulated Revenue |
||||||||||||||||||||||||||||||
| Marketing and trading margin (4) |
- | - | - | - | 101 | - | 101 | |||||||||||||||||||||||
| Other non-regulated operating revenue |
- | - | - | 12 | 16 | (13) | 15 | |||||||||||||||||||||||
|
Mark-to-market (3) |
- | - | - | - | 197 | (3) | 194 | |||||||||||||||||||||||
| Non-regulated revenue |
- | - | - | 12 | 314 | (16) | 310 | |||||||||||||||||||||||
| Total operating revenues |
$ | 2,092 | $ | 1,035 | $ | 276 | $ | 976 | $ | 314 | $ | (29) | $ 4,664 | |||||||||||||||||
(1) Other includes rental revenues which do not represent revenue from contracts with customers.
(2) Revenue related to Brunswick Pipeline’s service agreement with Repsol Energy.
(3) Revenue which does not represent revenues from contracts with customers.
(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with customers.
Remaining Performance Obligations:
Remaining performance obligations primarily represent gas transportation contracts, and long-term steam supply arrangements with fixed contract terms. As of June 30, 2026, the aggregate amount of the transaction price allocated to remaining performance obligations was $332 million (2025 – $458 million), including $11 million related to NMGC. This amount includes $121 million of future performance obligations related to a gas transportation contract between SeaCoast and PGS through 2040, and $20 million of future performance obligations related to asset management agreements between PGS and EES through 2030. This amount excludes contracts with an original expected length of one year or less and variable amounts for which Emera recognizes revenue at the amount to which it has the right to invoice for services performed. Emera expects to recognize revenue for the remaining performance obligations through 2040.
17
6. REGULATORY ASSETS AND LIABILITIES
A summary of regulatory assets and liabilities is provided below. For a detailed description regarding the nature of the Company’s regulatory assets and liabilities, refer to note 7 in Emera’s 2025 annual audited consolidated financial statements. Updates to regulatory environments are included below.
| As at millions of dollars |
June 30 2026 |
December 31 2025 | ||||
|
| ||||||
| Regulatory assets (1) |
||||||
| Deferred income tax regulatory assets |
$ | 1,440 | $ 1,385 | |||
| TEC capital cost recovery for early retired assets |
759 | 727 | ||||
| Pension and post-retirement medical plan |
320 | 316 | ||||
| TEC capital cost recovery for retired Polk Unit 1 components |
174 | 178 | ||||
| NSPI FAM |
140 | 102 | ||||
| Cost recovery clauses |
51 | 55 | ||||
| Storm cost recovery clauses |
37 | 206 | ||||
| Environmental remediations |
28 | 27 | ||||
| Deferrals related to derivative instruments |
18 | 36 | ||||
| Stranded cost recovery |
- | 25 | ||||
| Other (2) |
131 | 141 | ||||
| $ | 3,098 | $ 3,198 | ||||
| Current |
$ | 225 | $ 409 | |||
| Long-term |
2,873 | 2,789 | ||||
| Total regulatory assets |
$ | 3,098 | $ 3,198 | |||
| Regulatory liabilities (1) |
||||||
| Accumulated reserve -cost of removal |
$ | 783 | $ 729 | |||
| Deferred income tax regulatory liabilities |
759 | 751 | ||||
| Cost recovery clauses |
46 | 75 | ||||
| Storm cost recovery clauses |
37 | - | ||||
| Deferrals related to derivative instruments |
36 | 25 | ||||
| BLPC Self-insurance fund (“SIF”) (note 23) |
31 | 30 | ||||
| Other (2) |
52 | 59 | ||||
| $ | 1,744 | $ 1,669 | ||||
| Current |
$ | 198 | $211 | |||
| Long-term |
1,546 | 1,458 | ||||
| Total regulatory liabilities |
$ | 1,744 | $ 1,669 | |||
(1) On August 5, 2024, Emera announced an agreement to sell NMGC. As a result, NMGC’s assets and liabilities were classified as held for sale beginning in Q3 2024 and excluded from the table above. For further details on the pending transaction, refer to note 3.
(2) Comprised of regulatory assets and liabilities that are not individually significant.
Florida Electric Utility
On April 6, 2026, the Florida Public Service Commission (“FPSC”) established a docket for further study of certain purchased power costs recovered through the fuel adjustment clause. On April 15, 2026, TEC filed a petition with the FPSC seeking approval of revised depreciation rates for Bayside Station assets, which would decrease annual depreciation expense by approximately $20 million USD. On June 16, 2026, TEC and the Office of Public Counsel filed with the FPSC a motion to approve a settlement agreement for the revised depreciation rates to be effective on July 1, 2026. As part of the settlement agreement, TEC agreed to decrease fuel clause recovery by $10 million USD in 2026, which will be reflected on customer’s bills in 2027. TEC also agreed to not seek approval for an increase in base revenues effective prior to January 1, 2028, except for previously approved subsequent year adjustments from the 2024 rate case and large load customer tariffs required by statute. On August 4, 2026, the FPSC approved the settlement agreement.
18
On February 3, 2025, the FPSC issued the final order approving the rate case decision, effective January 1, 2025. In March 2025, two intervening parties each filed a notice of appeal to the Florida Supreme Court regarding the outcome of TEC’s 2024 base rate proceeding. On January 12, 2026, the intervening parties filed their briefs related to the appeal. On April 13, 2026, the FPSC and TEC filed responses to the briefs. To date, the Florida Supreme Court has not made a decision regarding this case.
Canadian Electric Utilities
NSPI
Base Rates:
On April 30, 2026, the Nova Scotia Energy Board (“NSEB”) approved the General Rate Application (“GRA”) with changes effective May 1, 2026. This results in an average annual customer rate increase of 1.2 per cent, and a further average increase of 2.5 per cent on January 1, 2027. Any under or over-recovery of fuel costs will be addressed through NSPI’s established FAM process with the NSEB. NSPI’s return on equity range will continue to be 8.75 per cent to 9.25 per cent, based on a common equity component of up to 40 per cent. The NSEB also approved the depreciation study completed in 2025 and continuation of the storm rider for each of 2026 and 2027. Additionally, the NSEB approved deferral of depreciation and financing costs for assets within the scope of NSPI’s Decarbonization Deferral Account as of December 31, 2025. NSPI has proposed to recover these costs through a rate reducing securitization transaction, the timing of which requires final support from the Province of Nova Scotia.
Extra Large Industrial Active Demand Control Customer Deferral (“ELIADC” Deferral):
On April 30, 2026, the NSEB approved the establishment of a regulatory asset allowing NSPI to defer revenue variances arising from differences between the current rate setting methodology for an ELIADC customer and a revised NSEB-approved methodology. The deferral is effective from May 1, 2026, until the earlier of December 31, 2027, or implementation of an approved methodology change. Amounts are recorded in “Regulated fuel for generation and purchased power” on the Condensed Consolidated Income Statement and the balance deferred as a “Regulatory Asset” on the Condensed Consolidated Balance Sheets.
NSPML
On June 25, 2026, NSPML submitted an application to the NSEB requesting recovery of $200 million in 2027 and $192 million in 2028 for costs associated with the Maritime Link.
On May 11, 2026, the NSEB issued its decision on NSPML’s 2026 assessment application, reducing NSPML’s approved regulated ROE from 9.0 per cent to 8.75 per cent and approved the collection of up to $198 million in Maritime Link costs for 2026, subject to a monthly holdback of up to $4 million if certain delivery requirements are not met. There was no holdback recorded year-to-date in 2026.
Other Electric Utilities
In November 2025, the Government of Barbados and BLPC agreed to new Transmission, Distribution, Sales and Dispatch (“T&D”) and Generation and Energy Storage (“G&S”) licenses. On May 11, 2026, BLPC’s new licenses became effective after the repeal of the previous license. The G&S license is valid until 2047, unless otherwise extended. The T&D License is valid for 30 years.
19
7. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME
| June 30 | Carrying Value as at December 31 |
Equity Income for the three months ended June 30 |
Equity Income (loss) for the six months ended June 30 |
Percentage of Ownership | ||||||||||||||||||||||
| millions of dollars |
2026 | 2025 | 2026 | 2025 | 2026 | 2025 | 2026 | |||||||||||||||||||
| NSPML |
$ | 456 | $ | 462 | $ | 10 | $ | 11 | $ | 22 | $ | 22 | 100.0 | |||||||||||||
| M&NP (1) |
110 | 108 | 5 | 4 | 10 | 10 | 12.9 | |||||||||||||||||||
| Lucelec (1) |
57 | 55 | 1 | 1 | 2 | 2 | 19.5 | |||||||||||||||||||
| WTI (2) |
9 | 9 | - | - | - | - | 50.0 | |||||||||||||||||||
| Bear Swamp (3) |
- | - | 16 | (2) | 19 | (1) | 50.0 | |||||||||||||||||||
| $ | 632 | $ | 634 | $ | 32 | $ | 14 | $ | 53 | $ | 33 | |||||||||||||||
(1) Emera has significant influence over the operating and financial decisions of these companies through Board representation and therefore, records its investment in these entities using the equity method.
(2) NSPI has a 50 per cent indirect voting interest in WTI. As of June 30, 2026, NSPI’s economic interest based on the $9 million invested is 9 per cent.
(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 $68 million (December 31, 2025 – $84 million) is recorded in Other long-term liabilities on the Condensed Consolidated Balance Sheets.
Emera accounts for its variable interest investment in NSPML as an equity investment (note 23). NSPML’s consolidated summarized balance sheet is as follows:
| As at millions of dollars |
June 30 2026 |
December 31 2025 | ||||
| Current assets |
$ | 56 | $ 40 | |||
| PP&E |
1,356 | 1,380 | ||||
| Regulatory assets |
761 | 782 | ||||
| Non-current assets |
26 | 27 | ||||
| Total assets |
$ | 2,199 | $ 2,229 | |||
| Current liabilities |
$ | 83 | $87 | |||
| Long-term debt (1) |
1,466 | 1,495 | ||||
| Non-current liabilities |
194 | 185 | ||||
| Equity |
456 | 462 | ||||
| Total liabilities and equity |
$ | 2,199 | $ 2,229 | |||
(1) The project debt has been guaranteed by the Government of Canada.
20
8. OTHER (EXPENSE) INCOME, NET
| Three months ended | Six months ended | |||||||||||||||
| For the | June 30 | June 30 | ||||||||||||||
| millions of dollars | 2026 | 2025 | 2026 | 2025 | ||||||||||||
| AFUDC - equity |
$ | 13 | $ | 19 | $ | 25 | $ | 37 | ||||||||
| Interest income |
6 | 10 | 11 | 20 | ||||||||||||
| Pension non-service cost recovery |
5 | 8 | 10 | 14 | ||||||||||||
| Loss on sale of GBPC (1) |
(21) | - | (21) | - | ||||||||||||
| FX (losses) gains |
(19) | 44 | (29) | 40 | ||||||||||||
| Other |
4 | 4 | 10 | 5 | ||||||||||||
| $ | (12) | $ | 85 | $ | 6 | $ | 116 | |||||||||
(1) For more information on the sale of GBPC, refer to note 3.
9. INCOME TAXES
The income tax provision, for the three and six months ended June 30, differs from that computed using the enacted Canadian federal statutory income tax rate for the following reasons:
| Three months ended | Six months ended | |||||||||||||||||||||||||||||
| For the | June 30 | June 30 | ||||||||||||||||||||||||||||
| millions of dollars | 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||||||||
| Income before provision for income taxes | $ | 99 | $ | 145 | $ | 810 | $ | 865 | ||||||||||||||||||||||
| Income taxes, at statutory income tax rate | 14 | 15 % | 22 | 15 % | 121 | 15 % | 130 | 15 % | ||||||||||||||||||||||
| Domestic reconciling items: | ||||||||||||||||||||||||||||||
| Investment tax credits |
(1) | (1) % | (3) | (2) % | (11) | (1) % | (29) | (3) % | ||||||||||||||||||||||
| Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities |
(1) | (1) % | - | - % | (11) | (1) % | (14) | (2) % | ||||||||||||||||||||||
| Net Part VI. Tax |
- | - % | 3 | 2 % | 8 | 1 % | 7 | 1 % | ||||||||||||||||||||||
| Valuation allowance |
(3) | (3) % | (4) | (3) % | (6) | (1) % | (5) | (1) % | ||||||||||||||||||||||
| Other |
- | - % | (5) | (3) % | (2) | - % | (6) | (1) % | ||||||||||||||||||||||
| Provincial income taxes (1) | (31) | (31) % | (24) | (16) % | 4 | - % | 19 | 2 % | ||||||||||||||||||||||
| Foreign reconciling items: | ||||||||||||||||||||||||||||||
| United States |
||||||||||||||||||||||||||||||
| Federal tax rate variance |
18 | 18 % | 13 | 9 % | 36 | 4 % | 29 | 3 % | ||||||||||||||||||||||
| Production tax credits |
(19) | (20) % | (17) | (12) % | (31) | (4) % | (26) | (3) % | ||||||||||||||||||||||
| State income tax, net of federal income tax benefit |
13 | 13 % | 13 | 9 % | 26 | 3 % | 25 | 3 % | ||||||||||||||||||||||
| Investment tax credits |
(19) | (19) % | (16) | (11) % | (19) | (2) % | (37) | (4) % | ||||||||||||||||||||||
| Amortization of deferred income tax regulatory liabilities |
(10) | (10) % | (12) | (8) % | (18) | (2) % | (21) | (2) % | ||||||||||||||||||||||
| Deferral and amortization of investment tax credits |
14 | 14 % | 11 | 8 % | 9 | 1 % | 29 | 3 % | ||||||||||||||||||||||
| Impairment charge |
- | - % | 13 | 9 % | - | - % | 13 | 2 % | ||||||||||||||||||||||
| Other |
(1) | (1) % | (1) | (1) % | (2) | - % | (3) | - % | ||||||||||||||||||||||
| Other foreign jurisdictions | 1 | 1 % | (2) | (2) % | - | - % | (1) | - % | ||||||||||||||||||||||
| Income tax expense (recovery) | $ | (25) | (25) % | $ | (9) | (6) % | $ | 104 | 13 % | $ | 110 | 13 % | ||||||||||||||||||
(1) The majority of provincial income taxes relate to Nova Scotia.
21
Canadian Tax Legislation Changes:
On March 26, 2026, Bill C-15, an Act to implement certain provisions of the 2025 budget tabled in Parliament on November 4, 2025, was enacted. Bill C-15, among other measures, reinstates the Accelerated Investment Incentive (“AII”) and introduces the Clean Electricity Investment Tax Credit (“CEITC”). The AII provides enhanced first-year capital cost allowance deductions, while the CEITC is a refundable tax credit of 15 per cent, reduced to 5 per cent if prescribed labour requirements are not met, on eligible property, including interprovincial and territorial transmission assets and qualifying refurbishments on eligible property. The enactment of Bill C-15 did not have a material impact on the Company year-to-date in 2026.
10. COMMON STOCK
Authorized: Unlimited number of non-par value common shares.
| Issued and outstanding: | millions of shares | millions of dollars | ||||||
| Balance, December 31, 2025 |
301.76 | $ | 9,387 | |||||
| Issuance of common stock under ATM program (1) |
2.66 | 184 | ||||||
| Issued under the DRIP, net of discounts |
2.08 | 141 | ||||||
| Senior management stock options exercised and ECSPP |
0.65 | 38 | ||||||
| Balance, June 30, 2026 |
307.15 | $ | 9,750 | |||||
(1) For the three months ended June 30, 2026, no common shares were issued under Emera’s ATM program. For the six months ended June 30, 2026, a total of 2,657,496 common shares were issued under Emera’s ATM program at an average price of $69.89 per share for gross proceeds of $186 million ($184 million net of after-tax issuance costs). As at June 30, 2026, an aggregate gross sales limit of $414 million remained available for issuance under the ATM program.
11. EARNINGS PER SHARE
The following table reconciles the computation of basic and diluted earnings per share:
| Three months ended
|
Six months ended
| |||||||||||||
| For the | June 30 | June 30 | ||||||||||||
| millions of dollars (except per share amounts) | 2026 | 2025 | 2026 | 2025 | ||||||||||
| Numerator |
||||||||||||||
| Net income attributable to common shareholders |
$ | 105.0 | $ | 135.0 | $ | 666.7 | $ 718.4 | |||||||
| Diluted numerator |
105.0 | 135.0 | 666.7 | 718.4 | ||||||||||
| Denominator |
||||||||||||||
| Weighted average shares of common stock outstanding – basic |
306.4 | 298.6 | 304.9 | 297.8 | ||||||||||
| Stock-based compensation |
1.0 | 0.5 | 1.0 | 0.4 | ||||||||||
| Weighted average shares of common stock outstanding – diluted |
307.4 | 299.1 | 305.9 | 298.2 | ||||||||||
| Earnings per common share |
||||||||||||||
| Basic |
$ | 0.34 | $ | 0.45 | $ | 2.19 | $ 2.41 | |||||||
| Diluted |
$ | 0.34 | $ | 0.45 | $ | 2.18 | $ 2.41 | |||||||
22
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 for-sale |
Net change in unrecognized pension and post- retirement benefit costs |
Total AOCI |
||||||||||||||||||
| For the six months ended June 30, 2026 |
| |||||||||||||||||||||||
| Balance, January 1, 2026 |
$ | 773 | $ | (81) | $ | 10 | $ | 2 | $ | 169 | $ | 873 | ||||||||||||
| OCI before reclassifications |
488 | (49) | - | (1) | - | 438 | ||||||||||||||||||
| Amounts reclassified from AOCI |
(25) | - | (1) | - | (5) | (31) | ||||||||||||||||||
| Net current period OCI |
463 | (49) | (1) | (1) | (5) | 407 | ||||||||||||||||||
| Balance, June 30, 2026 |
$ | 1,236 | $ | (130) | $ | 9 | $ | 1 | $ | 164 | $ | 1,280 | ||||||||||||
| For the six months ended June 30, 2025 |
| |||||||||||||||||||||||
| Balance, January 1, 2025 |
$ | 1,396 | $ | (163) | $ | 12 | $ | - | $ | 16 | $ | 1,261 | ||||||||||||
| OCI before reclassifications |
(685) | 89 | - | - | - | (596) | ||||||||||||||||||
| Amounts reclassified from AOCI |
- | - | (1) | - | (4) | (5) | ||||||||||||||||||
| Net current period OCI |
(685) | 89 | (1) | - | (4) | (601) | ||||||||||||||||||
| Balance, June 30, 2025 |
$ | 711 | $ | (74) | $ | 11 | $ | - | $ | 12 | $ | 660 | ||||||||||||
The reclassifications out of AOCI are as follows:
| Three months ended
|
Six months ended
|
|||||||||||||||||
| For the | June 30 | June 30 | ||||||||||||||||
| millions of dollars | 2026 | 2025 | 2026 | 2025 | ||||||||||||||
| Affected line item in the Unaudited Condensed Consolidated Interim Financial Statements |
Amounts reclassified from AOCI | |||||||||||||||||
| Realized gain on translation of self-sustaining foreign operations | ||||||||||||||||||
| Gain on disposition |
Other (expenses) income, net | $ | (25) | $ | - | $ | (25) | $ | - | |||||||||
| Gain on derivatives recognized as cash flow hedges | ||||||||||||||||||
| Interest rate hedge |
Interest expense, net | $ | (1) | $ | (1) | $ | (1) | $ | (1) | |||||||||
| Net change in unrecognized pension and post-retirement benefit costs |
| |||||||||||||||||
| Amounts reclassified into obligations |
Pension and post-retirement benefits | - | - | (5) | (4) | |||||||||||||
| Total reclassifications out of AOCI, for the period |
$ | (26) | $ | (1) | $ | (31) | $ | (5) | ||||||||||
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. |
23
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 and NMGC 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 | June 30 | December 31 | June 30 | December 31 | ||||||||||||
| millions of dollars | 2026 | 2025 | 2026 | 2025 | ||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
$ | 47 | $ | 22 | $ | 18 | $ | 33 | ||||||||
| FX forwards |
10 | 3 | - | 2 | ||||||||||||
| 57 | 25 | 18 | 35 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
29 | 51 | 26 | 50 | ||||||||||||
| Natural gas swaps, futures, forwards, physical contracts |
248 | 238 | 696 | 695 | ||||||||||||
| 277 | 289 | 722 | 745 | |||||||||||||
| Other derivatives: |
||||||||||||||||
| Equity derivatives |
32 | 8 | - | - | ||||||||||||
| FX forwards |
- | 8 | 17 | 1 | ||||||||||||
| 32 | 16 | 17 | 1 | |||||||||||||
| Total gross derivatives |
366 | 330 | 757 | 781 | ||||||||||||
| Impact of master netting agreements: |
||||||||||||||||
| Regulatory deferral |
(4) | (1) | (4) | (1) | ||||||||||||
| HFT derivatives |
(76) | (131) | (76) | (131) | ||||||||||||
| Total impact of master netting agreements |
(80) | (132) | (80) | (132) | ||||||||||||
| Less: Derivatives classified as held for sale (1) |
(17) | - | - | - | ||||||||||||
| Total derivatives |
$ | 269 | $ | 198 | $ | 677 | $ | 649 | ||||||||
| Current (2) |
234 | 156 | 509 | 534 | ||||||||||||
| Long-term (2) |
35 | 42 | 168 | 115 | ||||||||||||
| Total derivatives |
$ | 269 | $ | 198 | $ | 677 | $ | 649 | ||||||||
(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 June 30, 2026, the unrealized gain in AOCI was $10 million, after-tax (December 31, 2025 – $10 million, after-tax). For the three and six months ended June 30, 2026, unrealized gains of $1 million ($1 million for the three and six months ended June 30, 2025, respectively) were reclassified from AOCI into interest expense, net. 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 June 30 |
2026 | 2025 | ||||||||||||
| Unrealized (loss) gain in regulatory assets |
$ | 2 | $ | 1 | $ | (5) | $ (6) | |||||||
| Unrealized (loss) gain in regulatory liabilities |
14 | 5 | (3) | (14) | ||||||||||
| Realized loss (gain) in regulatory assets |
1 | - | (2) | - | ||||||||||
| Realized loss (gain) in regulatory liabilities |
(10) | - | 1 | - | ||||||||||
| Realized loss in inventory (1) |
- | - | 4 | - | ||||||||||
| Realized loss (gain) in regulated fuel for generation and purchased power (2) | 4 | (1) | 7 | - | ||||||||||
| Total change in derivative instruments |
$ | 11 | $ | 5 | $ | 2 | $ (20) | |||||||
|
|
||||||||||||||
| For the six months ended June 30 |
2026 | 2025 | ||||||||||||
| Unrealized (loss) gain in regulatory assets |
$ | 2 | $ | 4 | $ | (15) | $ (1) | |||||||
| Unrealized (loss) gain in regulatory liabilities |
49 | 6 | 17 | (18) | ||||||||||
| Realized loss (gain) in regulatory assets |
- | - | (3) | - | ||||||||||
| Realized loss (gain) in regulatory liabilities |
(11) | - | 3 | - | ||||||||||
| Realized loss (gain) in inventory (1) |
3 | - | 7 | (4) | ||||||||||
| Realized loss (gain) in regulated fuel for generation and purchased power (2) |
(3) | (1) | 8 | (2) | ||||||||||
| Total change in derivative instruments | $ | 40 | $ | 9 | $ | 17 | $ (25) | |||||||
(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 June 30, 2026, the Company had the following notional volumes designated for regulatory deferral that are expected to settle as outlined below:
| millions | 2026 | 2027-2028 | ||||
| Commodity swaps and forwards purchases: |
||||||
| Natural gas (MMBtu) |
5 | 10 | ||||
| Power (MWh) |
- | 1 | ||||
| FX forwards: |
||||||
| FX contracts (millions of USD) |
$ | 98 | $ 124 | |||
| Weighted average rate |
1.3433 | 1.3650 | ||||
| % of USD requirements |
59% | 25% | ||||
HFT Derivatives
The Company has recognized the following realized and unrealized gains with respect to HFT derivatives:
| Three months ended | Six months ended | |||||||||||
| For the | June 30 | June 30 | ||||||||||
| millions of dollars | 2026 | 2025 | 2026 | 2025 | ||||||||
| Power swaps and physical contracts in non-regulated operating revenues | $ | 3 | $ | - | $5 | $ - | ||||||
| Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues | 36 | (14 | ) | 375 | 464 | |||||||
| Total gains (losses) in net income |
$ | 39 | $ | (14 | ) | $380 | $ 464 | |||||
26
As at June 30, 2026, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:
| millions | 2026 | 2027 | 2028 | 2029 | 2030 and thereafter |
|||||||||||||||
| Natural gas purchases (MMBtu) |
283 | 174 | 53 | 31 | 45 | |||||||||||||||
| Natural gas sales (MMBtu) |
327 | 176 | 39 | 27 | 184 | |||||||||||||||
| Power purchases (MWh) |
1 | - | - | - | - | |||||||||||||||
| Power sales (MWh) |
1 | 1 | - | - | - | |||||||||||||||
Other Derivatives
As at June 30, 2026, the Company had equity derivatives in place to manage cash flow risk associated with forecasted future cash settlements of deferred compensation obligations and FX forwards in place to manage cash flow risk associated with forecasted USD cash inflows. The equity derivatives hedge the return on 3.2 million shares and extends until December of 2026. The FX forwards have a combined notional amount of $617 million USD and expire in 2026 through 2028.
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 June 30 | 2026 | 2025 | ||||||||||||
| Unrealized gain in OM&G | $ | - | $ | 10 | $ | - | $ 5 | |||||||
| Unrealized (loss) gain in other (expense) income, net | (16) | - | 43 | - | ||||||||||
| Realized loss in other (expense) income, net | - | - | (2) | - | ||||||||||
| Total (losses) gains in net income | $ | (16) | $ | 10 | $ | 41 | $ 5 | |||||||
| For the six months ended June 30 | 2026 | 2025 | ||||||||||||
| Unrealized gain in OM&G | $ | - | $ | 32 | $ | - | $ 25 | |||||||
| Unrealized gain (loss) in other (expense) income, net | (23) | - | 47 | - | ||||||||||
| Realized loss in other (expense) income, net | - | - | (10) | - | ||||||||||
| Total (losses) gains in net income |
$ | (23) | $ | 32 | $ | 37 | $ 25 | |||||||
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 assesses credit risk internally 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 June 30, 2026, the Company had $274 million (December 31, 2025 – $207 million) in financial assets considered to be past due, which had been outstanding for an average 80 days. The FV of these financial assets was $262 million (December 31, 2025 – $192 million), the difference of which is included in the allowance for credit losses. These assets primarily relate to accounts receivable from electric and gas revenue.
Cash Collateral
The Company’s cash collateral positions consisted of the following:
| As at millions of dollars |
June 30 2026 |
December 31 2025 | ||||
| Cash collateral provided to others |
$ | 121 | $ 193 | |||
| Cash collateral received from others |
$ | 5 | $ 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 June 30, 2026, the total FV of derivatives in a liability position was $677 million (December 31, 2025 – $649 million). If the credit ratings of the Company were reduced below investment grade, the full value of the net liability position could be required to be posted as collateral for these derivatives.
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 | June 30, 2026 | |||||||||||||
| millions of dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||
| Assets |
||||||||||||||
| Regulatory deferral: |
||||||||||||||
| Commodity swaps and forwards |
$ | 25 | $ | 18 | $ | - | $ 43 | |||||||
| FX forwards |
- | 10 | - | 10 | ||||||||||
| 25 | 28 | - | 53 | |||||||||||
| HFT derivatives: |
||||||||||||||
| Power swaps and physical contracts |
1 | 12 | 5 | 18 | ||||||||||
| Natural gas swaps, futures, forwards, physical contracts and related transportation |
14 | 158 | 11 | 183 | ||||||||||
| 15 | 170 | 16 | 201 | |||||||||||
| Other derivatives: |
||||||||||||||
| FX forwards |
- | - | - | - | ||||||||||
| Equity derivatives |
32 | - | - | 32 | ||||||||||
| 32 | - | - | 32 | |||||||||||
| Less: Derivatives classified as held for sale (1) |
- | (17 | ) | - | (17) | |||||||||
| Total assets |
72 | 181 | 16 | 269 | ||||||||||
| Liabilities |
||||||||||||||
| Regulatory deferral: |
||||||||||||||
| Commodity swaps and forwards |
11 | 3 | - | 14 | ||||||||||
| 11 | 3 | - | 14 | |||||||||||
| HFT derivatives: |
||||||||||||||
| Power swaps and physical contracts |
- | 12 | 4 | 16 | ||||||||||
| Natural gas swaps, futures, forwards and physical contracts |
17 | 276 | 337 | 630 | ||||||||||
| 17 | 288 | 341 | 646 | |||||||||||
| Other derivatives: |
||||||||||||||
| FX forwards |
- | 17 | - | 17 | ||||||||||
| - | 17 | - | 17 | |||||||||||
| Total liabilities |
28 | 308 | 341 | 677 | ||||||||||
| Net assets (liabilities) |
$ | 44 | $ | (127 | ) | $ | (325 | ) | $ (408) | |||||
(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, 2025 | |||||||||||||||
| millions of dollars | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Assets |
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
$ | 21 | $ | - | $ | - | $ | 21 | ||||||||
| FX forwards |
- | 3 | - | 3 | ||||||||||||
| 21 | 3 | - | 24 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
(1) | 29 | 7 | 35 | ||||||||||||
| Natural gas swaps, futures, forwards, physical contracts and related transportation |
1 | 88 | 34 | 123 | ||||||||||||
| - | 117 | 41 | 158 | |||||||||||||
| Other derivatives: |
||||||||||||||||
| FX forwards |
- | 8 | - | 8 | ||||||||||||
| Equity derivatives |
8 | - | - | 8 | ||||||||||||
| 8 | 8 | - | 16 | |||||||||||||
| Total assets |
29 | 128 | 41 | 198 | ||||||||||||
| Liabilities |
||||||||||||||||
| Regulatory deferral: |
||||||||||||||||
| Commodity swaps and forwards |
11 | 21 | - | 32 | ||||||||||||
| FX forwards |
- | 2 | - | 2 | ||||||||||||
| 11 | 23 | - | 34 | |||||||||||||
| HFT derivatives: |
||||||||||||||||
| Power swaps and physical contracts |
(4) | 31 | 7 | 34 | ||||||||||||
| Natural gas swaps, futures, forwards and physical contracts |
1 | 115 | 464 | 580 | ||||||||||||
| (3) | 146 | 471 | 614 | |||||||||||||
| Other derivatives: |
||||||||||||||||
| FX forwards |
- | 1 | - | 1 | ||||||||||||
| - | 1 | - | 1 | |||||||||||||
| Total liabilities |
8 | 170 | 471 | 649 | ||||||||||||
| Net assets (liabilities) |
$ | 21 | $ | (42) | $ | (430) | $ | (451) | ||||||||
The change in the FV of the Level 3 financial assets and liabilities was as follows:
| Three months ended | Six months ended | |||||||||||||||||||||||
| June 30, 2026 | June 30, 2026 | |||||||||||||||||||||||
|
HFT Derivatives |
HFT Derivatives |
|||||||||||||||||||||||
| millions of dollars | Power | Natural gas |
Total | Power | Natural gas |
Total | ||||||||||||||||||
| Assets |
||||||||||||||||||||||||
| Balance, beginning of period |
$ | 6 | $ | 13 | $ | 19 | $ | 7 | $ | 34 | $ | 41 | ||||||||||||
| Total realized and unrealized losses included in non-regulated operating revenues | (1) | (2) | (3) | (2) | (23) | (25) | ||||||||||||||||||
| Balance, June 30, 2026 |
$ | 5 | $ | 11 | $ | 16 | $ | 5 | $ | 11 | $ | 16 | ||||||||||||
| Liabilities |
||||||||||||||||||||||||
| Balance, beginning of period |
$ | 4 | $ | 289 | $ | 293 | $ | 7 | $ | 464 | $ | 471 | ||||||||||||
| Total realized and unrealized gains (losses) included in non-regulated operating revenues | - | 48 | 48 | (3) | (127) | (130) | ||||||||||||||||||
| Balance, June 30, 2026 |
$ | 4 | $ | 337 | $ | 341 | $ | 4 | $ | 337 | $ | 341 | ||||||||||||
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:
| June 30, 2026 | ||||||||||||||||||||||
| 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 | $ | 36.05 | $ | 180.25 | $94.31 | ||||||||||||||
| HFT derivatives – Natural gas swaps, futures, forwards and physical contracts | |
11 - |
|
337 | Third-party pricing | $2.05 | $19.36 | $10.08 | ||||||||||||||
| Total |
$ | 16 | $ | 341 | ||||||||||||||||||
| Net liability |
$ | 325 | ||||||||||||||||||||
(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 | ||||||||||||||||||
| June 30, 2026 |
$ | 19,587 | $ | 18,782 | $ | - | $ | 18,535 | $ | 247 | $ | 18,782 | ||||||||||||
| December 31, 2025 |
$ | 19,654 | $ | 18,956 | $ | - | $ | 18,535 | $ | 421 | $ | 18,956 | ||||||||||||
On June 15, 2026, Emera redeemed all $1.2 billion USD denominated 2016 hybrid notes which were designated as a hedge of the foreign currency exposure of its net investment in USD denominated operations. On the same date, Emera designated $750 million USD denominated intercompany balances related to the 2026 hybrid notes issued by Emera Finance, as a hedge of the foreign currency exposure of its net investment in its USD denominated operations. An after-tax foreign currency loss of $21 million was recorded in AOCI for the three months ended June 30, 2026 (2025 – $87 million after-tax gain) and an after-tax foreign currency loss of $49 million was recorded for the six months ended June 30, 2026 (2025 – $89 million after-tax loss) related to Emera’s net investment hedges.
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 $60 million for the three months ended June 30, 2026 (2025 – $42 million) and $100 million for the six months ended June 30, 2026 (2025 – $91 million). NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments. |
| • | Natural gas transportation capacity purchases from M&NP are reported in the Condensed Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues – non-regulated, totalled $3 million for the three months ended June 30, 2026 (2025 – $3 million) and $10 million for the six months ended June 30, 2026 (2025 – $11 million). |
As at June 30, 2026, Emera and its associated companies had $69 million due from related parties (December 31, 2025 – $35 million) recorded in “Receivables and other current assets”, and $35 million due to related parties (December 31, 2025 – $32 million) recorded in “Other Current Liabilities”, on the Condensed Consolidated Balance Sheets.
16. RECEIVABLES AND OTHER CURRENT ASSETS
| As at millions of dollars |
June 30 2026 |
December 31 2025 |
||||||
|
|
||||||||
| Customer accounts receivable – billed |
$ 1,069 | $ 1,265 | ||||||
|
|
||||||||
| Customer accounts receivable – unbilled |
390 | 400 | ||||||
|
|
||||||||
| Capitalized transportation capacity (1) |
350 | 238 | ||||||
|
|
||||||||
| Cash collateral provided to others |
121 | 193 | ||||||
|
|
||||||||
| Prepaid expenses |
135 | 105 | ||||||
|
|
||||||||
| Sales tax receivable |
93 | 84 | ||||||
|
|
||||||||
| Income tax receivable |
7 | 19 | ||||||
|
|
||||||||
| Allowance for credit losses |
(12) | (15) | ||||||
|
|
||||||||
| Other |
194 | 150 | ||||||
|
|
||||||||
| Total receivables and other current assets |
$ 2,347 | $ 2,439 | ||||||
|
|
||||||||
(1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract.
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 June 30 |
Six months ended June 30 |
||||||||||||||
| millions of dollars | 2026 | 2025 | 2026 | 2025 | ||||||||||||
|
|
||||||||||||||||
| DB pension plans |
||||||||||||||||
| Service cost |
$ | 9 | $ | 9 | $ | 18 | $ | 18 | ||||||||
|
|
||||||||||||||||
| Non-service cost: |
||||||||||||||||
| Interest cost |
29 | 28 | 57 | 57 | ||||||||||||
|
|
||||||||||||||||
| Expected return on plan assets |
(39) | (41) | (78) | (82) | ||||||||||||
|
|
||||||||||||||||
| Current year amortization of: |
||||||||||||||||
| Actuarial losses |
- | 1 | 1 | 1 | ||||||||||||
|
|
||||||||||||||||
| Regulatory asset |
4 | 2 | 8 | 5 | ||||||||||||
|
|
||||||||||||||||
| Total non-service costs |
(6) | (10) | (12) | (19) | ||||||||||||
|
|
||||||||||||||||
| Total DB pension plans |
3 | (1) | 6 | (1) | ||||||||||||
|
|
||||||||||||||||
| Non-pension benefit plans |
||||||||||||||||
| Service cost |
- | 1 | 1 | 2 | ||||||||||||
|
|
||||||||||||||||
| Interest cost |
3 | 3 | 6 | 6 | ||||||||||||
|
|
||||||||||||||||
| Expected return on plan assets |
- | - | (1) | (1) | ||||||||||||
|
|
||||||||||||||||
| Current year amortization of: |
- | |||||||||||||||
| Actuarial losses |
- | - | (1) | - | ||||||||||||
|
|
||||||||||||||||
| Past service costs |
- | (1) | - | (1) | ||||||||||||
|
|
||||||||||||||||
| Total non-service costs |
3 | 2 | 4 | 4 | ||||||||||||
|
|
||||||||||||||||
| Total non-pension benefit plans |
3 | 3 | 5 | 6 | ||||||||||||
|
|
||||||||||||||||
| Total DB pension and non-pension benefit plans |
$ | 6 | $ | 2 | $ | 11 | $ | 5 | ||||||||
|
|
||||||||||||||||
Emera’s pension and non-pension contributions related to these DB plans for the three months ended June 30, 2026 were $13 million (2025 – $14 million), and for the six months ended June 30, 2026 were $26 million (2025 – $27 million). Annual employer contributions to the DB pension plans are estimated to be $34 million for 2026. Emera’s contributions related to the DC plans for the three months ended June 30, 2026 were $15 million (2025 – $15 million) and $26 million (2025 – $28 million) for the six months ended June 30, 2026.
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 2025 annual audited consolidated financial statements, and below for 2026 short-term debt financing activity.
Recent financing activities for Emera and its subsidiaries are discussed below by segment:
Canadian Electric Utilities
On May 1, 2026, NSPI amended its $500 million non-revolving facility to extend the maturity date from May 21, 2026, to May 21, 2027. There were no other material changes in commercial terms from the prior agreement.
33
Other
On June 4, 2026, Emera entered into a $500 million non-revolving facility which matures on June 4, 2027. The credit agreement contains customary representations and warranties, events of default and financial and other covenants. The non-revolving facility’s interest rates are referenced to the Term CORRA or prime rate, plus a margin.
On February 20, 2026, Emera amended its $200 million unsecured non-revolving facility to extend the maturity date from February 20, 2026 to February 19, 2027. There were no other material changes to the terms from the prior agreement.
19. LONG-TERM DEBT
For details regarding long-term debt, refer to note 26 in Emera’s 2025 annual audited consolidated financial statements, and below for 2026 long-term debt financing activity.
Recent financing activities for Emera and its subsidiaries are discussed below by segment:
Canadian Electric Utilities
On July 14, 2026, the holders of NSPI’s $40 million senior unsecured notes exercised their option to extend the maturity date from August 14, 2026, to August 14, 2056.
On June 19, 2026, NSPI amended its $800 million revolving credit facility to extend the maturity date from June 24, 2029, to June 19, 2031. There were no other material changes in commitment amount, maturity, or interest from the prior agreement.
On April 17, 2026, NSPI issued $300 million in unsecured notes that bear interest at 3.95 per cent with a maturity date of April 17, 2031.
Gas Utilities and Infrastructure
On June 30, 2026, NMGC executed an agreement to issue $140 million USD in senior unsecured notes. The agreement included $70 million USD senior unsecured notes that bear interest at 5.35 per cent with a maturity date of July 28, 2031, and $70 million USD senior unsecured notes that bear interest at 5.73 per cent with a maturity date of October 20, 2036. Proceeds from the notes due in 2031 were received on July 28, 2026, and were used for the repayment of maturing long-term debt. Proceeds from notes due in 2036 will be received on October 20, 2026, and will be used for the repayment of short-term debt outstanding. Therefore, $140 million USD of short-term debt was classified as long-term liabilities associated with held for sale as of June 30, 2026.
On May 5, 2026, PGS executed an agreement to issue $200 million USD in senior notes. The agreement included $50 million USD senior notes that bear interest at 4.91 per cent with a maturity date of May 5, 2031, $100 million USD senior notes that bear interest at 5.39 per cent with a maturity date of May 5, 2036, and $50 million USD senior notes that bear interest at 5.64 per cent with a maturity date of August 20, 2041.
Other Electric Utilities
On March 18, 2026, BLPC amended its $10 million USD note to extend the maturity date from March 2026 to May 2031, reduced the interest rate from 2.05 per cent to 1.90 per cent, and change the principal payment from $0.25 million USD quarterly to $0.5 million USD semi-annually.
On February 9, 2026, BLPC entered into a $46 million USD non-revolving facility which matures in 2031 and bears interest at 1.80 per cent. As of June 30, 2026, BLPC has drawn $44 million USD on the facility.
34
Other
On June 19, 2026, Emera amended its $1.3 billion revolving credit facility to extend the maturity date from June 24, 2029, to June 19, 2031. There were no other material changes in commercial terms from the prior agreement.
On March 4, 2026, EUSHI Finance, Emera Finance, EUSHI and Emera filed a new shelf registration statement on Form F-10 and Form F-3 (“Registration Statement”), with the Nova Scotia Securities Commission (“NSSC”) and the US Securities and Exchange Commission (“SEC”) under the US/Canada Multijurisdictional Disclosure System. The Registration Statement was filed in connection with the prospective offer and issue by EUSHI Finance or Emera Finance of one or more series of senior and/or subordinated unsecured debt securities (“Debt Securities”), in an aggregate principal amount of up to $2.25 billion USD, during the 25-month period that the short form base shelf prospectus contained in the Registration Statement (“Base Shelf Prospectus”), including any further amendments thereto, remains valid. The Debt Securities may be offered in one or more transactions, at prices, with maturities and on terms to be set forth in one or more prospectus supplements to be filed with the NSSC and the SEC at the time of any such offering.
On March 23, 2026, Emera Finance completed an issuance of $750 million USD aggregate principal amount of fixed-to-fixed reset rate junior subordinated notes, pursuant to the prospectus supplement, dated March 23, 2026, to the Base Shelf Prospectus. The issuance consisted of $375 million USD aggregate principal amount of 6.65 per cent Series A fixed-to-fixed reset rate junior subordinated notes due 2056 and $375 million USD aggregate principal amount of 6.85 per cent Series B fixed-to-fixed reset rate junior subordinated notes due 2056 (collectively, the “Notes”). The Notes are fully and unconditionally guaranteed, on a joint, several and subordinated basis, by Emera and EUSHI.
On March 27, 2026, Emera Finance completed an issuance of $750 million USD aggregate principal amount of senior notes pursuant to the prospectus supplement, dated March 27, 2026, to the Base Shelf Prospectus. The issuance consisted of $450 million USD aggregate principal amount of senior notes that bear interest at a rate of 4.50 per cent with a maturity date of April 1, 2029, and $300 million USD aggregate principal amount of senior notes that bear interest at a rate of 5.20 per cent with a maturity date of April 1, 2033. The senior notes are fully and unconditionally guaranteed, on a joint and several basis, by Emera and EUSHI.
Together these issuances were used to redeem all $1.2 billion USD of Emera’s outstanding 6.75 per cent fixed-to-floating subordinated notes - Series 2016-A due 2076, and to repay Emera US Finance LP’s $750 million USD 3.55 per cent senior unsecured note on June 15, 2026, upon maturity.
35
20. COMMITMENTS AND CONTINGENCIES
A. Commitments
As at June 30, 2026, contractual commitments (excluding pensions and other post-retirement obligations, long-term debt and asset retirement obligations) for each of the next five years and in aggregate thereafter consisted of the following:
| millions of dollars | 2026 | 2027 | 2028 | 2029 | 2030 | Thereafter | Total | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Purchased power (1) |
$ | 206 | $ | 432 | $ | 413 | $ | 461 | $ | 454 | $ | 6,423 | $ | 8,389 | ||||||||||||||
|
|
||||||||||||||||||||||||||||
| Transportation (2)(3) |
576 | 739 | 557 | 473 | 407 | 3,104 | 5,856 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Fuel, gas supply and storage (4) |
388 | 322 | 151 | 198 | 81 | 58 | 1,198 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Capital projects |
249 | 88 | 45 | 1 | 9 | - | 392 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| Other |
94 | 97 | 186 | 61 | 49 | 323 | 810 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||
| $ | 1,513 | $ | 1,678 | $ | 1,352 | $ | 1,194 | $ | 1,000 | $ | 9,908 | $ | 16,645 | |||||||||||||||
|
|
||||||||||||||||||||||||||||
As detailed below, commitments at June 30, 2026 include those related to NMGC. On completion of the sale of NMGC, all remaining future commitments will be transferred to the buyer. For further details on the pending transaction, refer to note 3.
(1) Annual requirement to purchase electricity from Independent Power Producers or other utilities over varying contract lengths.
(2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. Includes a commitment of $121 million related to a gas transportation contract between PGS and SeaCoast through 2040, and $20 million of future performance obligations related to asset management agreements between PGS and EES through 2030.
(3) Includes $167 million related to NMGC (2026: $15 million, 2027: $35 million, 2028: $32 million, 2029: $22 million, 2030: $21 million, and $42 million thereafter).
(4) Includes $284 million related to NMGC (2026: $54 million, 2027: $102 million, 2028: $45 million, 2029: $42 million, 2030: $41 million).
NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. On May 11, 2026, the NSEB issued its decision on NSPML’s 2026 assessment application, approving the collection of up to $198 million from NSPI for recovery of costs associated with the Maritime Link in 2026, subject to a monthly holdback of up to $4 million.
The timing and amounts payable to NSPML for the remainder of the 38-year commitment period are subject to NSEB approval.
Emera has committed to obtain certain transmission rights in New Brunswick during summer periods (April through October, inclusive) for Newfoundland and Labrador Hydro’s (“NLH”) use, if requested, effective August 15, 2021 and continuing for 50 years. As transmission rights are contracted, the obligations are included within “Other” in the above table.
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 June 30, 2026, the aggregate financial liability of the Florida utilities is estimated to be $16 million ($11 million USD), primarily at PGS. This estimate assumes that other involved PRPs are credit-worthy entities. This amount has been accrued and is primarily reflected in the long-term liability section under “Other long-term liabilities” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.
The estimated amounts represent only the portion of cleanup costs attributable to the Florida utilities. The estimates to perform the work are based on the Florida utilities’ experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.
36
In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-worthy and are likely to continue to be credit-worthy for the duration of remediation work. However, in those instances that they are not, the Florida utilities could be liable for more than their actual percentage of remediation costs. Other factors that could impact these estimates include additional testing and investigation which could expand the scope of cleanup activities, additional liability that might arise from cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in base rate proceedings.
Other Legal Proceedings
Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company.
C. Principal Financial Risks and Uncertainties
For information on principal financial risks which could materially affect the Company in the normal course of business, refer to note 28 in Emera’s 2025 annual audited consolidated financial statements. Risks associated with derivative instruments and FV measurements are discussed in note 13 and note 14. There have been no material changes to the principal financial risks as of June 30, 2026.
D. Guarantees and Letters of Credit
Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2025
audited annual consolidated financial statements, with material updates as noted below:
The Company has standby letters of credit and surety bonds in the amount of $174 million USD (December 31, 2025 – $271 million USD) to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed annually, as required.
Emera, on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The expiry date of this letter of credit was extended to June 2027. The amount committed as at June 30, 2026 was $72 million (December 31, 2025 – $70 million).
Emera’s guarantee of $66 million USD relating to outstanding notes of ECI was automatically terminated in Q2 2026, and no obligations remain outstanding.
21. CUMULATIVE PREFERRED STOCK
For details regarding cumulative preferred stock, refer to note 29 in Emera’s 2025 annual audited consolidated financial statements, and below for 2026 preferred stock activity.
On April 9, 2026, Emera announced that it would not redeem the currently outstanding Cumulative Minimum Rate Reset First Preferred Shares, Series J (“Series J Shares”) on May 15, 2026 (the “Conversion Date”). There were 8.0 million Series J Shares outstanding.
On April 15, 2026, Emera announced a dividend rate of 6.345 per cent per annum on the Series J Shares during the five-year period commencing on May 15, 2026, and ending on (and inclusive of) May 14, 2031. Emera also announced a dividend rate of 5.598 per cent on the Cumulative Floating Rate First Series K Shares (“Series K Shares”) for the three-month period commencing on May 15, 2026 and ending on (inclusive of) August 14, 2026.
37
During the conversion period between April 15, 2026, and April 30, 2026, the holders of Series J Shares had the right, at their option, to convert all or any of their Series J Shares, on a one-for-one basis, into Series K Shares. On May 5, 2026, Emera announced that after having taken into account all conversion notices received from holders of its outstanding Series J Shares by the April 30, 2026 deadline for conversion notices, less than the 1,000,000 Series J Shares required to give effect to conversions into Series K Shares were tendered for conversion. As a result, in accordance with certain rights, privileges, restrictions and conditions attaching to the Series J Shares, none of Emera’s outstanding Series J Shares were converted into Series K Shares on May 15, 2026. On the Conversion Date there were 8.0 million Series J Shares outstanding.
22. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
| For the | Six months ended June 30 | |||||||
| millions of dollars | 2026 | 2025 | ||||||
|
|
||||||||
| Changes in non-cash working capital: |
||||||||
| Inventory |
$ | (24) | $ | (53) | ||||
|
|
||||||||
| Receivables and other current assets |
277 | (259) | ||||||
|
|
||||||||
| Accounts payable |
(300) | (222) | ||||||
|
|
||||||||
| Other current liabilities |
38 | 27 | ||||||
|
|
||||||||
| Total non-cash working capital |
$ | (9) | $ | (507) | ||||
|
|
||||||||
| Supplemental disclosure of non-cash activities: |
||||||||
| Common share dividends reinvested |
$ | 141 | $ | 153 | ||||
|
|
||||||||
| Increase (decrease) in accrued capital expenditures |
$ | 38 | $ | (30) | ||||
|
|
||||||||
| Reclassification of short-term debt and current portion of long-term debt to long-term debt |
$ | 140 | $ | - | ||||
|
|
||||||||
| Supplemental disclosure of operating activities: |
||||||||
| Net change in short-term regulatory assets and liabilities |
$ | 108 | $ | 77 | ||||
|
|
||||||||
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, NLH was deemed the primary beneficiary of the asset for financial reporting purposes, as it has authority over the majority of the direct activities expected to most significantly impact the economic performance of the Maritime Link. Thus, Emera began recording the Maritime Link as an equity investment.
BLPC established a SIF, primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission, and distribution systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered that, in substance, activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. Any withdrawal of SIF fund assets by the Company would be subject to existing regulations. Emera’s consolidated VIE in the SIF is recorded as “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.
38
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 | June 30, 2026 | December 31, 2025 | ||||||||||||||
|
|
||||||||||||||||
| millions of dollars | Total assets |
Maximum exposure to loss |
Total assets |
Maximum exposure to loss |
||||||||||||
|
|
||||||||||||||||
| Unconsolidated VIEs in which Emera has variable interests |
||||||||||||||||
| NSPML (equity accounted) |
$ | 456 | $ | 6 | $ | 462 | $ | 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 August 7, 2026, the date the unaudited condensed consolidated interim financial statements were issued.
39
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 six months ended June 30, 2026.
The following earnings coverage ratio is calculated on a consolidated basis for the twelve months ended June 30, 2026.
| Twelve months ended June 30, 2026 | ||
| Earnings Coverage (1) |
1.81 |
(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 $110 million for the twelve months ended June 30, 2026. Emera’s interest requirements for the twelve months ended June 30, 2026 amounted to $1,098 million. Emera’s consolidated income before interest and income tax for the twelve months ended June 30, 2026 was $2,190 million, which is 1.81 times Emera’s aggregate preferred dividends and interest requirements for this period.
Exhibit 99.4
Emera Reports 2026 Second Quarter Financial Results
HALIFAX, Nova Scotia – Today, August 7, 2026, Emera Inc. (“Emera”) (TSX/NYSE: EMA) reported 2026 second quarter financial results1.
Highlights
| • | Delivered Q2 2026 adjusted EPS2 of $0.69 and reported EPS of $0.34. |
| • | Positioned to achieve 2026 adjusted EPS2 growth above the annual target range of 5-7%3 and remain committed to 5-7% adjusted EPS2 growth through 20303. |
| • | Strengthened year-to-date operating cash flow4 by 8% versus the first six months of 2025. |
| • | Safely advanced more than $1.7B of customer-focused infrastructure investments in the first half of 2026, while remaining on track to execute $4B annual capital plan this year. |
“Our second quarter results reflect disciplined execution across the business and continued solid progress on our long-term growth strategy,” said Scott Balfour, President and CEO of Emera Inc. “During the first half of the year, we successfully concluded our portfolio optimization strategy with regulatory approval of the New Mexico Gas transaction and closing the sale of Grand Bahama Power Company. This further strengthens the company and sharpens our focus. Our utilities invested more than $1.7 billion on behalf of our customers in the same timeframe, supporting reliability, resiliency and growth across our jurisdictions. Looking ahead, our focused portfolio of high-quality regulated utilities positions Emera to continue delivering the reliable energy customers depend on, while creating long-term value for shareholders.“
Q2 2026 Financial Results
Q2 2026 adjusted net income attributable to common shareholders (“adjusted net income”)2 was $212 million, or $0.69 per common share, compared to $236 million, or $0.79 per common share, in Q2 2025. The decrease was primarily due to increased interest expense and foreign exchange (“FX”) losses at Corporate; decreased earnings at New Mexico Gas Company (“NMGC”); and lower earnings due to the sale of Grand Bahama Power Company (“GBPC”).
Q2 2026 reported net income was $105 million, or $0.34 per common share, compared to net income of $135 million, or $0.45 per common share, in Q2 2025. Reported income also included a $59 million increase in mark-to-market (“MTM”) losses, after-tax, and the $19 million loss on sale of GBPC, after tax and transaction costs, partially offset by the $72 million charges related to the pending sale of NMGC recognized in Q2 2025.
1
2026 YTD Financial Results
Year-to-date adjusted net income1 was $627 million or $2.06 per common share, compared with $615 million or $2.07 per common share year-to-date in 2025. Year-to-date adjusted net income1 increased $12 million primarily due to increased earnings at PGS, EES and TEC, higher equity earnings at Bear Swamp and higher income tax recovery at Corporate. These were partially offset by increased interest expense and higher operating, maintenance and general (“OM&G”) expenses at Corporate; lower earnings at NSPI and NMGC; and lower earnings due to the sale of GBPC.
Year-to-date reported net income was $667 million or $2.19 per common share, compared with net income of $718 million or $2.41 per common share, year-to-date in 2025. Year-to-date reported net income also included a $116 million decrease in MTM gain, after-tax, and the $19 million loss on sale of GBPC, partially offset by the $72 million charges related to the pending sale of NMGC recognized in Q2 2025.
The translation impacts of a stronger CAD on USD denominated earnings decreased net income attributable to common shareholders by $13 million in Q2 2026 and $43 million year-to-date compared to the same periods in 2025. In Q2 2026, the impact of the change in FX rates on adjusted net income was nil. Year-to-date, strengthening of the CAD decreased adjusted net income by $17 million, compared to the same period in 2025. These impacts include the effect of the FX hedges used to mitigate translation risk of USD earnings, which are included in Corporate in the Other segment.
| (1) | Financial information is presented in CAD unless otherwise specified. |
| (2) | See “Non-GAAP Financial Measures and Ratios” noted below and “Segment Results and Non-GAAP Reconciliation” below for reconciliation to nearest USGAAP measure. |
| (3) | Adjusted EPS growth guidance uses 2024 as base year. |
| (4) | Reflects operating cash flow pre-working capital. |
2
Segment Results and Non-GAAP Reconciliation
| For the | Three months ended | Six months ended | ||||||||||||||
| millions of dollars (except per share amounts) | June 30 | June 30 | ||||||||||||||
| Adjusted Net Income 1,2 |
2026 | 2025 | 2026 | 2025 | ||||||||||||
|
|
||||||||||||||||
| Florida Electric Utility |
$ | 261 | $ | 260 | $ | 441 | $ | 424 | ||||||||
| Canadian Electric Utilities |
16 | 17 | 102 | 138 | ||||||||||||
| Gas Utilities and Infrastructure |
55 | 48 | 191 | 168 | ||||||||||||
| Other Electric Utilities |
5 | 12 | 13 | 12 | ||||||||||||
| Other 3 |
(125) | (101) | (120) | (127) | ||||||||||||
|
|
||||||||||||||||
| Adjusted net income 1,2 |
$ | 212 | $ | 236 | $ | 627 | $ | 615 | ||||||||
|
|
||||||||||||||||
| MTM (loss) gain, after-tax4 |
(88) | (29) | 59 | 175 | ||||||||||||
| Loss on sale of GBPC, after tax and transaction costs5 |
(19) | - | (19) | - | ||||||||||||
| Charges related to the pending sale of NMGC, after-tax6 |
- | (72) | - | (72) | ||||||||||||
|
|
||||||||||||||||
| Net income attributable to common shareholders |
$ | 105 | $ | 135 | $ | 667 | $ | 718 | ||||||||
|
|
||||||||||||||||
| EPS (Basic) |
$ | 0.34 | $ | 0.45 | $ | 2.19 | $ | 2.41 | ||||||||
|
|
||||||||||||||||
| Adjusted EPS (Basic)1,2 |
$ | 0.69 | $ | 0.79 | $ | 2.06 | $ | 2.07 | ||||||||
|
|
||||||||||||||||
1 See “Non-GAAP Financial Measures and Ratios” noted below.
2 Excludes the effect of MTM adjustments; loss on sale of GBPC, after tax and transaction costs; and charges related to the pending sale of NMGC.
3 Lower earnings, quarter-over-quarter, primarily due to increased interest expense and Corporate FX losses on translation of USD short-term debt balances and decreased contributions from EES, partially offset by increased equity earnings at Bear Swamp and higher income tax recovery. Higher earnings, year-over-year, due to higher contributions from EES, increased equity earnings at Bear Swamp and higher income tax recovery, partially offset by increased interest expense and higher OM&G.
4 Net of income tax recovery of $37 million for the three months ended June 30, 2026 (2025 – $13 million recovery) and $24 million income tax expense for the six months ended June 30, 2026 (2025 – $71 million expense).
5 Net of income tax recovery of $2 million for the three and six months ended June 30, 2026.
6 Represents a $71 million non-cash impairment charge, after-tax, and $1 million in transaction costs, after-tax for the three and six months ended June 30, 2025. Amounts are net of an income tax recovery of $5 million for the three and six months ended June 30, 2025.
Consolidated Financial Review
The following table highlights significant quarter-over-quarter and year-over-year changes in adjusted net income from 2025 to 2026:
3
| For the millions of dollars | Three months ended June 30 |
Six months ended June 30 |
||||||
| Adjusted net income – 20251,2 |
$ | 236 | $ | 615 | ||||
| Operating Unit Performance |
||||||||
| Increased earnings at PGS due to higher revenue from new base rates and higher off-system sales, partially offset by higher OM&G and depreciation | 15 | 33 | ||||||
| Increased equity earnings at Bear Swamp due to business interruption insurance received related to an unplanned outage in 2025 and higher generation | 19 | 23 | ||||||
| Increased earnings year-over-year at TEC due to higher revenue from new base rates and higher off-system sales, partially offset by higher depreciation, increased state and municipal taxes, higher interest expense and the impact of a stronger CAD | 1 | 17 | ||||||
| Decreased earnings year-over-year at NSPI due to lower income tax recovery as a result of higher clean technology investment tax credits in 2025 ($18 million), higher OM&G and higher depreciation expense. These were partially offset by higher sales volumes | - | (36) | ||||||
| Decreased earnings due to the sale of GBPC in May 2026 | (7) | (7) | ||||||
| Decreased earnings quarter-over-quarter at EES due to timing of hedge settlements related to storage positions and higher transport costs. Increased earnings year-over year due to favourable market conditions that led to higher natural gas prices and increased volatility that created profitable opportunities | (10) | 26 | ||||||
| Decreased earnings at NMGC primarily due to higher OM&G | (12) | (12) | ||||||
| Corporate | ||||||||
| Increased income tax recovery quarter-over-quarter primarily due to an increased loss before provision for income taxes, partially offset by an unfavourable deferred income tax asset valuation adjustment. Increased income tax recovery year-over-year due to an increased loss before provision for income taxes | 3 | 9 | ||||||
| Increase OM&G, pre-tax, primarily due to lower gain on the long-term incentive hedge and increased costs as a result of New York Stock Exchange listing | (1) | (13) | ||||||
| Increased Corporate FX losses on the translation of USD short-term debt balances. Year-over-year is partially offset by a decreased realized loss on FX hedges | (9) | (4) | ||||||
| Increased interest expense, pre-tax, due to higher long-term debt primarily resulting from timing of financings, partially offset by interest earned on debt proceeds held in invested cash. Year-over-over is also partially offset by lower short-term debt | (21) | (28) | ||||||
| Other Variances | (2) | 4 | ||||||
| Adjusted net income – 20261,2 | $ | 212 | $ | 627 | ||||
1 See “Non-GAAP Financial Measures and Ratios” noted below and “Segment Results and Non-GAAP Reconciliation” for reconciliation to nearest US GAAP measure.
2 Excludes the effect of MTM adjustment; loss on sale of GBPC, after tax and transaction costs; and charges related to the pending sale of NMGC, net of tax.
4
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 Q2 2026 MD&A, which is incorporated herein by reference and can be found on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov. Reconciliation to the nearest GAAP measure is included in “Segment Results and Non-GAAP Reconciliation” above.
Forward-Looking Information
This news release contains forward-looking information within the meaning of applicable Canadian securities laws and forward-looking statements within the meaning of applicable US securities laws including, without limitation, the U.S. Private Securities Litigation Reform Act of 1995 (collectively, “forward-looking information”) with respect to Emera, including without limitation, statements about: Emera’s plans to achieve 2026 adjusted EPS2 growth above the annual target range of 5-7%3 and remain committed to 5-7% adjusted EPS2 growth through 2030; the Company’s capital plans being on track for 2026; Emera’s focused portfolio of high-quality regulated utilities enabling it to continue to deliver reliable energy to customers and create long-term value for shareholders; and the pending sale of NMGC. . Forward-looking information is typically identified by words such as “anticipate,” “expect,” “intend,” “plan,” “target,” “believe,” “forecast,” “estimate,” “will,” “may,” “should,” and similar expressions suggesting future outcomes. Undue reliance should not be placed on this forward-looking information, which applies only as of the date hereof. By its nature, forward-looking information requires Emera to make assumptions and is subject to inherent risks and uncertainties. These statements reflect Emera management’s current beliefs and are based on information currently available to Emera management. There is a risk that predictions, forecasts, conclusions and projections that constitute forward-looking information will not prove to be accurate, that Emera’s assumptions may not be correct and that actual results may differ materially from those expressed or implied by such forward-looking information. The forward-looking information in this news release is made only as of the date hereof, and except as required by law, Emera disclaims any intention or obligation to update or revise any forward-looking information as a result of new information, future events or otherwise. Additional detailed information about these assumptions, risks and uncertainties is included in Emera’s securities regulatory filings, including under the heading “Enterprise Risk and Risk Management” in Emera’s annual Management’s Discussion and Analysis, and under the heading “Principal Financial Risks and Uncertainties” in the notes to Emera’s annual and interim financial statements, which can be found on SEDAR+ at www.sedarplus.ca or on EDGAR at www.sec.gov.
5
Teleconference Call
The company will be hosting a teleconference today, Friday, August 7, 2026, at 9:30 a.m. Atlantic (8:30 a.m. Eastern) to discuss the Q2 2026 financial results.
Analysts and other interested parties in North America are invited to participate by dialing 1-800-717-1738. International parties are invited to participate by dialing 1-289-514-5100. Participants should dial in at least 10 minutes prior to the start of the call. No pass code is required.
A live and archived audio webcast of the teleconference will be available on the Company’s website, www.emera.com. A replay of the teleconference will be available on the Company’s website two hours after the conclusion of the call.
About Emera
Emera (TSX/NYSE: EMA) is a leading North American provider of energy services headquartered in Halifax, Nova Scotia, with investments in regulated electric and natural gas utilities, and related businesses and assets. The Emera family of companies delivers safe, reliable energy to approximately 2.7 million customers in the United States, Canada and the Caribbean. Our team of 7,600 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, SVP, Capital Markets
902-233-2674
dave.bezanson@emera.com
Emera Inc.
Media
Emera Corporate Communications
media@emera.com
6
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
June 30, 2026.
2. No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.
3. Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.
4. Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.
5. Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings
| A. | designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that |
| i. | material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and |
| ii. | information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and |
| B. | designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP. |
5.1 Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (COSO) Internal Control-Integrated Framework.
5.2 ICFR – material weakness relating to design: N/A
5.3 Limitation on scope of design: The issuer has disclosed in its interim MD&A
| a. | the fact that the issuer’s other certifying officer(s) and I have limited the scope of our design of DC&P and ICFR to exclude controls, policies and procedures of: |
| i. | a proportionately consolidated entity in which the issuer has an interest; |
| ii. | a special purpose entity in which the issuer has an interest; or |
| iii. | a business that the issuer acquired not more than 365 days before the last day of the period covered by the interim filings; and |
| b. | summary financial information about the proportionately consolidated entity, special purpose entity or business that the issuer acquired that has been proportionately consolidated or consolidated in the issuer’s financial statements. |
6. Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on April 1, 2026 and ended on June 30, 2026 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.
| Date: August 7, 2026 |
| (s) Scott Balfour
|
| Scott Balfour |
| President and Chief Executive Officer |
Exhibit 99.6
FORM 52-109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE
I, Jared Green, Chief Financial Officer of Emera Incorporated, certify the following:
1. Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Emera Incorporated (the “issuer”) for the interim period ended
June 30, 2026.
2. No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.
3. Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.
4. Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.
5. Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings
| A. | designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that |
| i. | material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and |
| ii. | information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and |
| B. | designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP. |
5.1 Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (COSO) Internal Control-Integrated Framework.
5.2 ICFR – material weakness relating to design: N/A
5.3 Limitation on scope of design: The issuer has disclosed in its interim MD&A
| a. | the fact that the issuer’s other certifying officer(s) and I have limited the scope of our design of DC&P and ICFR to exclude controls, policies and procedures of: |
| i. | a proportionately consolidated entity in which the issuer has an interest; |
| ii. | a special purpose entity in which the issuer has an interest; or |
| iii. | a business that the issuer acquired not more than 365 days before the last day of the period covered by the interim filings; and |
| b. | summary financial information about the proportionately consolidated entity, special purpose entity or business that the issuer acquired that has been proportionately consolidated or consolidated in the issuer’s financial statements. |
6. Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on April 1, 2026 and ended on June 30, 2026 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.
| Date: August 7, 2026 |
| (s) Jared Green
|
| Jared Green |
| Chief Financial Officer |