Eversource Energy delivers electricity and natural gas to customers in Connecticut, Massachusetts and New Hampshire. Its third-quarter 2026 filing shows that selling its water business strengthened cash and reduced debt. In the first nine months, operating cash of $3.07 billion barely covered $3.05 billion of cash investment in utility assets. That leaves the timing of customer payments, borrowing and a potentially large transmission refund central to funding the next stage of investment.
Period: third quarter and first nine months ended September 30, 2026. Research cutoff: November 7, 2026, New York time. Subsequent developments discussed below are identified by their source dates.
1. Higher delivery rates helped, but did not prevent an earnings decline
Rate increases supported the utilities, while financing costs, regulatory decisions and smaller tax benefits weighed on consolidated profit. Eversource’s revenue is an imperfect guide to this result. Much of the money it collects pays for electricity, gas and state-mandated programs, with matching costs passed through to customers. Changes in those collections can move revenue without creating a corresponding change in profit.
The reported results show two different patterns. Third-quarter revenue fell, and operating profit fell somewhat faster. Across the first nine months, revenue increased modestly, operating profit slipped, and profit available to common shareholders declined much more sharply.
| Consolidated results; USD millions except percentages and EPS | Third quarter 2026 | Third quarter 2025 | First nine months 2026 | First nine months 2025 |
|---|---|---|---|---|
| Revenue | 2,978.9 | 3,220.6 | 10,386.4 | 10,177.0 |
| Operating profit | 629.7 | 688.7 | 2,246.8 | 2,278.1 |
| Operating margin, calculated | 21.1% | 21.4% | 21.6% | 22.4% |
| Profit available to common shareholders | 346.0 | 367.5 | 1,006.5 | 1,271.1 |
| Common-shareholder profit / revenue, calculated | 11.6% | 11.4% | 9.7% | 12.5% |
| Diluted earnings per share, USD | 0.92 | 0.99 | 2.67 | 3.44 |
Source: Eversource third-quarter 2026 Form 10-Q, consolidated income statements, p. 2. Margins use the unrounded statement amounts. Common-shareholder profit excludes subsidiary preferred-stock interests.
The revenue decline did not reflect less electricity moving through Eversource’s networks. Third-quarter retail electric deliveries rose 2.7%, from 13,727 to 14,103 gigawatt-hours. First-nine-month deliveries rose 1.8%, to 39,347 gigawatt-hours. Gas deliveries increased 3.4% in the quarter but declined 0.3% over nine months.
Most of these volumes have limited direct effects on earnings. Regulators allow the Connecticut and Massachusetts electric utilities, and all three gas utilities, to adjust collections so that approved distribution revenue is largely separated from customer usage. New Hampshire’s electric utility remains the main exception. Customers can also choose competing energy suppliers while continuing to pay Eversource for delivery. Its central business challenge is therefore recovering the cost of its networks, rather than winning commodity sales from another supplier.
Lower collections for state-mandated electric programs explain much of the revenue movement. These revenues declined by $322.9 million in the quarter and $703.9 million over nine months. Meanwhile, wholesale power sales increased, partly because NSTAR Electric began selling output purchased under its Hydro-Québec contract. The company earns no margin on these mandated energy purchases and resales. Regulatory accounting adjusts expenses to match the recoverable costs, which explains why the large revenue changes did not pass directly into profit.
Source: 2026 Form 10-Q, MD&A, “Sales Volumes,” “Tracked Distribution Revenues” and “Wholesale market sales revenue,” pp. 57–60.
The more useful test is what each delivery business earned. Electric distribution benefited from approved rate increases and mechanisms that recover investment costs. Those benefits were largely consumed by higher depreciation, interest and property taxes, plus Connecticut’s rejection of some previously deferred storm costs.
Gas distribution presents the clearest quarter-versus-year distinction. Its quarterly loss deepened partly because Massachusetts rate design shifted when revenue is recovered during the year. Over nine months, however, rate increases lifted gas profit substantially. Reading the summer loss alone would miss that improvement.
| Business contribution to common-shareholder profit; USD millions | Third quarter 2026 | Third quarter 2025 | First nine months 2026 | First nine months 2025 |
|---|---|---|---|---|
| Electric distribution, reported | 200.9 | 221.6 | 574.1 | 571.6 |
| Electric transmission, excluding designated refund charge | 182.0 | 185.5 | 590.0 | 593.0 |
| Natural gas distribution, reported | -43.4 | -16.8 | 281.6 | 236.9 |
| Water distribution, excluding sale loss | 0.0 | 18.9 | 17.9 | 36.8 |
| Parent and other companies, excluding offshore wind charge | 6.5 | 33.3 | -137.8 | -92.2 |
Source: 2026 Form 10-Q, MD&A earnings reconciliation and explanations, pp. 45–47. The exclusions are management’s non-GAAP measures; the complete consolidated bridge appears in Calculation note A. Water contributed only through its June 30, 2026 sale. These are disclosed business contributions, not a sum of subsidiary operating profits.
At the consolidated level, first-nine-month interest expense increased by $157.3 million to $1,069.4 million. Long-term borrowing costs and regulatory interest adjustments outweighed lower interest on short-term borrowings. Other income increased by $88.9 million, partly offsetting that pressure. It included income calculated from pension plans and a return recorded on money committed to unfinished construction. Neither represents customer cash collected for energy delivery during the period. A separate $36 million gain came from selling a nonphysical asset, with the cash recorded under investing activities.
Tax comparisons explain much of the gap between operating and net profit. Nine-month pretax income declined only $9.8 million, while income-tax expense increased $254.7 million. In the third quarter of 2025, tax-return adjustments produced $283 million of benefits, including a $165 million net benefit from reversing an allowance against offshore wind tax benefits and recording offsetting tax charges. The comparable 2026 tax-return adjustment was a $41 million benefit. The unusually favorable prior-year tax result makes the reported profit decline larger than the deterioration in operating profit.
Management’s adjusted earnings also require care. They declined 1.5% over nine months and 21.8% in the third quarter. The 2026 nine-month adjusted result still includes the $40.8 million pretax storm-cost charge, a $40 million pretax reduction in depreciation connected with the 2020 EGMA acquisition, the $36 million pretax intangible-asset sale gain, and the $41 million tax-return benefit. “Adjusted” therefore does not mean a clean measure of repeatable delivery earnings. The supported conclusion is that higher regulated revenues helped, but had not yet overcome the company’s financing and regulatory pressures.
Source: 2026 Form 10-Q, Notes 1E, 3 and 10, pp. 21, 24 and 35; MD&A, pp. 45–47 and 61–62. The 2025 offshore wind adjustment includes tax benefits also discussed in the tax footnote; those benefits must not be counted twice.
2. Customer collections left almost no cash after construction
Operating cash covered cash spending on property and equipment, but left only $15.7 million before dividends and offshore wind payments. That narrow remainder existed even though Eversource generated substantially more operating cash than accounting profit.
Depreciation is one reason for the difference. Eversource deducts the use of long-lived assets from profit over many years, although the construction cash is spent at another time. Its cash-flow statement therefore adds depreciation back to profit. The statement also reverses the current-period Aquarion and offshore wind accounting charges before showing the relevant cash transactions elsewhere.
The more important operating issue is when customers pay for costs the company has already incurred. Eversource reported $514.9 million less recovery through two Connecticut cost mechanisms than in the first nine months of 2025. It also paid vendors $54.2 million more for storm work. Better collections in other regulatory mechanisms and on customer receivables partly offset those pressures, leaving total operating cash down 4.0%.
| Consolidated cash allocation; USD millions | First nine months 2026 | First nine months 2025 |
|---|---|---|
| Cash from operations | 3,068.3 | 3,197.5 |
| Cash investment in property, plant and equipment | 3,052.6 | 3,175.4 |
| Remainder after that investment, calculated | 15.7 | 22.2 |
| Common dividends paid in cash | 871.3 | 816.4 |
| Subsidiary preferred dividends paid in cash | 5.6 | 5.6 |
| Offshore wind settlement payments | 233.0 | 141.3 |
| Remainder after these uses, calculated | -1,094.2 | -941.3 |
Source: 2026 Form 10-Q, consolidated cash-flow statement, p. 5; MD&A, “Cash Flows,” p. 50. Spending and payments are shown as positive uses; the final row subtracts them from operating cash. Calculations use unrounded amounts.
The $15.7 million remainder is a narrowly defined free-cash-flow measure: operating cash less the cash-flow statement’s investment in property, plant and equipment. It excludes offshore wind settlement payments and asset-sale receipts. Asset-removal payments already included in operating cash are not subtracted again.
This cash investment measure also differs from management’s $3.14 billion of first-nine-month capital expenditures. The latter includes construction accounting adjustments and items such as work incurred but not yet paid, asset-removal costs and financing allowances recorded during construction. Neither measure provides a complete maintenance-versus-expansion split. Eversource’s disclosed project purposes, discussed below, provide a better explanation of what the spending buys.
Dividends used considerably more cash than remained after construction. This does not mean the company exhausted its financing options: the water sale supplied cash, and debt markets remained accessible. It does mean that the stronger cash balance came from more than the operating business’s ability to fund itself. Future refunds would compete with dividends and construction for those financing resources.
Source: 2026 Form 10-Q, MD&A, “Cash Flows” and “Business Development and Capital Expenditures,” pp. 50–51. Calculation note B reconciles profit, operating cash and the closing cash balance.
3. Selling Aquarion reduced borrowing, while the energy networks kept growing
The water sale improved liquidity without stopping investment in electricity and gas delivery. Aquarion was sold on June 30 for a transaction value of approximately $2.4 billion, including about $650 million of debt repaid or transferred. The cash-flow statement records $2,334.1 million of sale proceeds and separately includes $612.4 million of Aquarion debt repayment in financing cash flows. After that disclosed repayment, the difference was approximately $1.72 billion, before any other cash-flow items or final purchase-price adjustment.
The transaction removed a water business that had earned $36.8 million in the first nine months of 2025. It also removed approximately $2 billion of net physical assets and $662.4 million of goodwill. Goodwill records acquisition value beyond the identifiable assets acquired after subtracting their obligations. Eversource recognized a $111.4 million loss on the sale. Management traded those future water earnings for immediate financial capacity; the cash-flow results show why that capacity mattered.
Source: 2026 Form 10-Q, cash-flow statement, p. 5; Note 18, p. 42; debt repayments, p. 49. The sale also involved a $10 million customer rate-stabilization contribution, return of $5.8 million held in escrow and $29 million of additional transaction costs. The $1.72 billion calculation is not presented as a separate fully net transaction-proceeds measure.
The balance sheet makes the resulting trade-off visible. Financing debt declined by $936.0 million, commercial paper was fully repaid, and unrestricted cash increased. Yet property and equipment remained slightly above year-end despite the removal of Aquarion’s assets. Construction in progress rose from $3.16 billion to $3.64 billion, showing that substantial spending was still tied up in unfinished projects.
| Consolidated financial position; USD millions | September 30, 2026 | December 31, 2025 |
|---|---|---|
| Unrestricted cash and cash equivalents | 525.4 | 135.4 |
| Net receivables plus unbilled revenue | 1,879.6 | 2,122.2 |
| Materials, supplies, gas and renewable-credit inventory | 414.7 | 491.6 |
| Net property, plant and equipment | 46,034.0 | 45,931.0 |
| Goodwill | 3,571.3 | 4,233.8 |
| Regulatory assets, current and long-term | 6,707.6 | 7,693.7 |
| Total assets | 62,584.4 | 63,786.7 |
| Financing debt, calculated | 29,178.9 | 30,114.9 |
| Accounts payable | 1,710.6 | 1,859.7 |
| Regulatory liabilities, current and long-term | 5,900.4 | 5,538.1 |
| Long-term derivative liabilities | 0.0 | 753.1 |
| Deferred income-tax liabilities | 6,034.5 | 5,647.2 |
| Common shareholders’ equity | 16,419.6 | 16,197.3 |
Source: 2026 Form 10-Q, balance sheet, p. 1; Notes 2–4, pp. 22–25. Financing debt includes notes payable, current and long-term debt, and rate-reduction bonds; it excludes leases and operating obligations. The selected rows are not intended to sum to total assets or liabilities. Calculation note C gives the complete balance-sheet equality.
The decline in regulatory assets should not be read as nearly $1 billion of cash collected. These assets are costs that Eversource expects to recover through future bills. A major part of the decrease came from the Hydro-Québec purchase contract changing accounting value. Higher forward energy prices turned its long-term derivative liability into an asset, removing the matching regulatory asset. Customers receive the contract’s benefits or bear its recoverable costs, so the revaluation did not create a comparable operating profit. Amounts owed back to customers, or collected for costs not yet incurred, appear as regulatory liabilities rather than borrowing from lenders. The Aquarion sale also removed a business that held $234.7 million of regulatory assets at year-end.
Receivables and unbilled revenue fell, and the operating cash-flow statement confirms a $135.7 million cash benefit from their movement. The balance-sheet decrease is larger because sales, write-offs, provisions and the water sale also affect the balances. Inventory fell by $76.9 million, but the filing does not provide a consolidated bridge separating those causes. These balance reductions therefore provide less evidence of improved collections than the cash-flow statement itself.
Customers’ unpaid bills remain significant. The allowance for expected collection losses increased from $580.5 million to $588.5 million. The company added both expense and costs deferred for future recovery from customers, while writing off old receivables. New expected losses and old bills written off explain the movement; the reconciliation in Calculation note C shows the amounts.
Deferred income-tax liabilities also increased, by $387.3 million. They represent tax obligations whose accounting and payment dates differ. The cash-flow statement reverses $240.3 million of deferred tax expense within its profit-to-cash calculation; the balance-sheet increase is not an equal current-period cash payment.
Source: 2026 Form 10-Q, balance sheet and cash-flow statement, pp. 1 and 5; Notes 1C, 2 and 4, pp. 19–20 and 22–25.
Debt repayment helped liquidity, but refinancing still costs more. Eversource issued $1.5 billion of junior subordinated notes in February with initial rates of 6.10% and 6.35%. Their initial annual coupons total $93.4 million. Meanwhile, some debt repaid during the year carried rates as low as 1.40%. The new borrowings funded several uses, so this is not a one-for-one refinancing comparison; it does explain why lower debt at September 30 can coexist with higher interest expense over the nine months.
At September 30, $2.875 billion of ordinary long-term debt was classified as due within one year, alongside $43.2 million of rate-reduction bonds. Eversource had $2.65 billion of unused commercial-paper capacity backed by revolving credit facilities, plus $525.4 million of unrestricted cash. The paper programs and their backing facilities are the same source of capacity and must not be added twice. The revolving facilities were extended in October to October 11, 2031.
Those resources give Eversource flexibility, but refinancing and continued operating cash remain important. The credit agreements described in the annual filing limit borrowing relative to total capital, while subsidiary dividend restrictions affect how cash can reach the parent. The simple debt total above is not the contractual covenant calculation. Debt terms, historical maturity schedules and lease commitments are summarized in Calculation note D.
Source: 2026 Form 10-Q, balance sheet and MD&A liquidity discussion, pp. 1 and 48–50; 2025 Form 10-K, Notes 8, 9 and 17, pp. 109, 113 and 138.
4. Transmission refunds could arrive before the appeal is decided
The recorded refund liability covers only the bottom of Eversource’s disclosed exposure. The dispute concerns how much profit transmission owners were allowed to collect through customer rates over many years. In March 2026, the Federal Energy Regulatory Commission set a 9.57% base return on equity, down from the 10.57% previously billed, and ordered refunds with interest for specified historical periods. That return applies to the shareholder-funded portion of regulated network investment.
There are two distinct effects. First, the lower allowed return reduces earnings from existing transmission assets. Using its 2025 investment base, Eversource estimated a roughly $70 million annual after-tax earnings reduction, partly offset by about $5 million from changes in transmission incentives. These are company estimates under that rate structure, not a forecast of the final 2027 outcome.
Second, the historical refund could require a much larger cash payment. The liability recorded at September 30 was $63 million, including $31.1 million of interest. The disclosed possible total extended to approximately $965 million. The upper end includes approximately $902 million for the period from October 16, 2014 through March 19, 2026, beyond the first complaint’s fifteen-month refund period.
Sources: 2026 Form 10-Q, Note 9C, pp. 32–33, and MD&A, pp. 52–53; FERC’s March 19, 2026 meeting summary, item E-1, confirming the replacement 9.57% base return and disposition of the four complaints.
The difference between the liability and the upper estimate is not a forecast loss. Eversource had not finalized the long-dated refund calculations and recorded the low end because it did not consider another amount a better estimate. Nevertheless, the filing expressly expects additional liabilities for the retroactive period before the appeal concludes. That makes the gap a current funding issue, rather than merely a remote legal possibility.
The schedule matters as much as the range. The court denied a request to suspend the retroactive refund obligation in August. Refunds are due by May 20, 2027, while Eversource believes an appeal decision could arrive in the second half of 2027. Without another court or regulatory action or processing delay, payments are expected to begin early in 2027. A successful appeal could therefore come after cash has left the company.
Management is also seeking a higher return for future transmission service. Its separate request for an 11.39% base return was suspended until November 30, 2026, subject to refund and a hearing process. That proceeding could improve future earnings, but a requested or provisionally effective rate is not a final entitlement to keep the revenue. A separate Connecticut challenge to a transmission participation incentive carries an estimated $12 million annual after-tax earnings exposure if the incentive is removed.
Source: 2026 Form 10-Q, Note 9C and MD&A, pp. 32–33 and 52–53; updated risk factor, p. 69. The $12 million estimate uses 2025 actual data and concerns a separate proceeding.
Connecticut’s storm decision illustrates the other side of regulatory timing: cash that Eversource has already spent but has not yet recovered. In July, PURA approved $869.4 million of storm costs from 2018–2023, deferred review of $63.3 million, and disallowed $40.8 million. The disallowance became an operating expense in the third quarter.
The approved amount is not all fresh cash still to come. After amounts already collected or approved for collection through existing rates, $667.9 million remained for consideration under a proposed bond financing. Such financing would allow the utility to receive cash sooner while customers repay the bonds through future bills. A decision is expected in January 2027. Eversource’s November presentation identifies storm financing as a means of reducing debt, but approval and execution remain necessary.
PURA also rejected recovery of financing costs incurred before its July decision. The requested $397 million of carrying costs had not been recorded as an asset, so the denial did not create another $397 million write-off. It nevertheless means Eversource has borne financing costs while waiting years to recover storm spending. Together, the transmission and storm cases show why regulatory permission to earn revenue and the date cash actually arrives must be assessed separately.
Sources: 2026 Form 10-Q, Note 2 and MD&A, pp. 22–23 and 54; November 5, 2026 earnings presentation, slide 14. The October 15 storm-decision appeal remained pending in the filing.
5. Revolution Wind is complete, but the sale still requires cash
Construction completion reduces an important source of uncertainty; it does not settle Eversource’s payment to the buyer. Eversource sold its 50% interests in South Fork Wind and Revolution Wind to Global Infrastructure Partners in September 2024. The agreement retained obligations for cost overruns and adjustments tied to the projects’ final economics. The company stopped owning the projects while remaining responsible for specified financial outcomes.
The remaining liability declined during 2026 because cash payments exceeded the additional costs recognized during the period.
| Offshore wind contingent liability; USD millions | Amount |
|---|---|
| Liability at December 31, 2025 | 448.158 |
| Additional expense recognized in the first nine months of 2026 | 194.000 |
| Cash payments in the first nine months of 2026 | -233.001 |
| Liability at September 30, 2026 | 409.157 |
Source: 2026 Form 10-Q, balance sheet and cash-flow statement, pp. 1 and 5; Note 9E, pp. 34–35. The bridge uses pretax expense and cash payments. The related earnings charge after tax was $164.0 million.
This exposure has a history. Eversource recorded an estimated $365 million obligation when it completed the 2024 sales, followed by an additional $284 million pretax charge in 2025 and $194 million in 2026. The 2025 increase reflected disclosed construction setbacks, insurance, tariff effects and the interruption caused by a stop-work order. An exit from ownership was therefore not an immediate exit from construction risk.
The strongest favorable evidence is now physical progress. The project owner’s website states that Revolution Wind entered commercial operations in October 2026. Eversource’s November 6 filing reports the owners’ November announcement that construction was complete and expects reconciliation of the sale adjustment in 2027. Completion should help establish final costs and the contractual completion date, narrowing the period during which additional construction delays can affect the adjustment.
Sources: 2026 Form 10-Q, Note 9E, pp. 34–35; Revolution Wind project-owner overview, commercial-operation and ownership information accessed for the November 7 cutoff. The operational milestone does not itself determine the completion date defined in Eversource’s sale agreement.
Tax-credit eligibility remains a material condition. The sale price assumed federal investment tax credits at a 40% level; a lower qualifying amount could create another loss. Eversource also disclosed a separate guarantee of up to $300 million supporting Revolution Wind tax positions through June 2035, as well as construction and funding guarantees. In October 2026, it issued three guarantees with maximum exposure of $972 million to support the sale of Revolution Wind investment tax credits. These maximum guarantees are not additional booked losses and should not simply be added to the $409.2 million liability.
Eversource believes the September liability is adequate, and the filing records no new third-quarter offshore wind charge. The business implication is cautiously favorable: completion moves the issue toward settlement, but the cash retained from selling Aquarion still has to accommodate obligations from an earlier divestiture.
Source: 2026 Form 10-Q, Notes 9B and 9E, pp. 31–32 and 34–35.
6. The investment plan has clear uses, but revenue recovery sets the pace
Eversource has a substantial pipeline of network work; its benefit depends on completing projects and collecting approved charges soon enough to cover their cost. Management’s November presentation forecasts $26.5 billion of capital investment for 2026–2030, excluding Aquarion. This is a plan to expand and maintain the asset base on which the utilities provide service and seek regulated earnings.
The current spending mix shows what that means. Of $2.21 billion of distribution capital expenditures during the first nine months, $1.05 billion was classified as aging infrastructure, $915.9 million as basic business needs, and $246.1 million as load growth and other work. Those categories include replacing electric cables and substations, replacing cast-iron and bare-steel gas pipes, buying meters and equipment, and adding capacity. The company is funding both continued service and new demand; the entire budget should not be described as expansion.
Sources: 2026 Form 10-Q, MD&A distribution capital-expenditure table and descriptions, p. 51; November 5 earnings presentation, slide 12. Distribution expenditures include Aquarion spending before its sale and use management’s capital-expenditure basis, not the cash-only measure in Section 2.
The Greater Cambridge Energy Program is a concrete example of investment tied to demand. It will add an underground substation and associated lines to serve rising electricity needs and improve reliability. Its estimated cost is $1.84 billion, with initial transmission service planned for June 2029 and later portions entering service through 2031. Only $300.4 million had been spent by September 30. It therefore represents a substantial future funding requirement, with permits and construction timing still affecting delivery.
The TIDE transmission project provides evidence that Eversource can win new regional work as well as maintain existing networks. ISO New England selected the joint Eversource–Central Maine Power proposal through a competitive evaluation of system needs, technical feasibility and regional costs and benefits. The project links northern New England resources more effectively with southern demand. Eversource’s estimated share is about $700 million, with service anticipated in 2032. The November presentation identifies about $400 million of its spending in 2027–2030 as incremental to the base plan. It is a future construction opportunity, not current operating revenue.
Sources: 2026 Form 10-Q, MD&A, “Greater Cambridge Energy Program” and “ISO-NE Longer-Term Transmission Planning RFP,” p. 51; ISO New England’s selection explanation, July 31, updated to reference its August 14 final report; November 5 earnings presentation, slides 12 and 14.
The immediate earnings opportunity is closer to home: getting approved rates to catch up with costs. CL&P’s July application sought approximately $451 million of additional annual base revenue, excluding the specified historical storm-cost effects, and proposed a four-year rate plan beginning July 2027. Approval would affect how quickly network investment and operating costs reach customer bills. The request is revenue, not profit, and was still under review.
There is evidence of progress elsewhere. New Hampshire approved $23.6 million of supplemental annual revenue effective August 1, 2026. Massachusetts approved NSTAR Gas’s $21 million increase effective November 1. NSTAR Electric separately requested a $66.6 million increase for January 2027, with a decision expected by year-end. These examples show that Eversource’s operating outlook depends on several jurisdictions with different review schedules.
Sources: Eversource second-quarter 2026 Form 10-Q, MD&A, “CL&P Distribution Rate Case”; third-quarter 2026 Form 10-Q, MD&A, “Regulatory Developments and Rate Matters,” p. 55; November 5 earnings presentation, slides 8 and 14.
Connecticut’s smart-meter proposal demonstrates the constraint. The project could improve metering and network operations, but recovery terms remained unresolved. The filing puts capital and operating costs at about $1.3 billion. Management’s separate $1 billion potential-investment figure concerns capital spending, so the two figures are not interchangeable. Until the regulatory framework is settled, this remains conditional investment rather than an assured addition to earnings.
Management narrowed its full-year 2026 adjusted EPS forecast to $4.62–$4.70 and retained a 5%–7% long-term EPS growth target through 2030, using the $4.66 midpoint as the base. It expects annual growth toward the upper half of that range by 2028. Those targets depend on the rate and funding decisions described above. The recent decline in adjusted earnings, upcoming refunds and higher financing costs provide concrete reasons to distinguish that plan from results already achieved.
Source: 2026 Form 10-Q, earnings outlook, p. 44, and CL&P advanced-meter discussion, pp. 54–55; November 5 earnings presentation, slide 12. Management did not reconcile forecast adjusted EPS to GAAP EPS because future excluded items could not be predicted with reasonable certainty.
7. The business is more focused, but the cash transition is unfinished
Eversource has improved its financing position while retaining a demanding set of cash commitments. Selling Aquarion reduced borrowing and concentrated the company on electricity and gas networks. Higher gas earnings, approved rate increases and the selection of new transmission work support the operating case for that focus.
The remaining challenge is turning those networks into enough timely cash to fund construction, distributions and obligations from past decisions. Transmission refunds may be payable before the appeal is resolved, and the offshore wind adjustment still needs settlement. The favorable path is concrete: completed wind construction leads to a manageable final payment, regulators permit timely recovery of network and storm spending, and new investment produces earnings faster than financing and operating costs rise. A large refund or further delay in collecting approved costs would use financial capacity that management intends to devote to the utility program.
Source: 2026 Form 10-Q, Notes 9C, 9E and 18; MD&A liquidity, capital expenditure and regulatory discussions, pp. 48–55. This conclusion draws on the operating and funding evidence set out above.
Reporting basis:
This analysis uses Eversource Energy and subsidiaries’ consolidated U.S. GAAP accounts in Form 10-Q, accession 0001628280-26-071541, filed November 6, 2026, for the period ended September 30, 2026. The SEC index identifies Eversource as CIK 0000072741. The combined filing also contains separate subsidiary statements; those were not substituted for the consolidated accounts. Quarterly comparisons cover July–September, cumulative comparisons cover January–September, and balance-sheet comparisons use December 31, 2025. Aquarion’s results remain within the presented consolidated comparative figures through its disposal.
The research cutoff is November 7, 2026, New York time. The principal dated updates verified are the November 6 filing, November 4 earnings release and November 5 presentation, supplemented by the project-owner information cited in Section 5. This is not a representation that every public development through the cutoff was independently checked. Dollar amounts are U.S. dollars. Tables generally round to millions; calculations use the underlying statement precision where available.
Sources: SEC filing index; filed XBRL instance; November 4 earnings release. XBRL checks used the 2026 U.S. GAAP taxonomy, dollar or share units as applicable, and Eversource consolidated contexts without subsidiary or segment dimensions. Where the instance repeated a fact at different rounding levels, the financial-statement precision was used.
Calculation notes:
A. Reported profit and management’s adjusted profit
The following table starts with common-shareholder profit and adds back only the charges management excluded. All adjustments are after tax. It keeps the prior-year comparison on the same basis.
| USD millions | Third quarter 2026 | Third quarter 2025 | First nine months 2026 | First nine months 2025 |
|---|---|---|---|---|
| Reported common-shareholder profit | 346.0 | 367.5 | 1,006.5 | 1,271.1 |
| Add: Aquarion sale charge | 0.0 | 0.0 | 111.4 | 0.0 |
| Add: offshore wind charge, net of designated tax benefits | 0.0 | 75.0 | 164.0 | 75.0 |
| Add: designated FERC refund charge | 0.0 | 0.0 | 43.9 | 0.0 |
| Management’s adjusted profit | 346.0 | 442.5 | 1,325.8 | 1,346.1 |
| Reported diluted EPS, USD | 0.92 | 0.99 | 2.67 | 3.44 |
| Management’s adjusted diluted EPS, USD | 0.92 | 1.19 | 3.52 | 3.64 |
The 2026 offshore wind charge was $194.0 million before tax and $164.0 million after tax, implying a $30.0 million tax benefit. The 2025 adjustment was $284.0 million of pretax expense less $209.0 million of designated tax benefits, leaving $75.0 million. The designated first-quarter FERC charge was $60.4 million before tax and $43.9 million after tax. Aquarion’s sale loss appears as both a $111.4 million operating expense and a $111.4 million after-tax adjustment. These are the company’s disclosed adjustments; the report does not create an additional adjusted result by mixing pretax and after-tax items.
Nine-month revenue growth is $209.395 million divided by $10,177.048 million, or 2.1%. The common-shareholder profit decline is $264.530 million divided by $1,271.066 million, or 20.8%. Operating margins are operating profit divided by revenue; common-shareholder margins use common-shareholder profit instead. The nine-month operating margin declined by 0.75 percentage points before rounding.
Diluted average shares increased from 369.619 million to 377.080 million over nine months, a calculated 2.0%. Management attributes $0.05 of the nine-month EPS comparison to the larger share count. At September 30, issued shares were 383.144 million and treasury shares were 6.230 million, leaving 376.913 million outstanding. The nine-month increase in outstanding shares comprised 289,044 newly issued shares and 1,207,177 shares released from treasury. Treasury releases served compensation, retirement-plan matching and dividend-reinvestment obligations; they were not share retirements. The quarter’s disclosed open-market purchases were only 2,492 shares for retirement-plan matching, with none under a publicly announced repurchase program.
Source: 2026 Form 10-Q, pp. 2–3, Notes 13–15, pp. 36–37; MD&A reconciliation, p. 45; Part II, Item 2, p. 70.
B. How profit becomes cash, and where the cash ended
This bridge uses total consolidated net income, including the subsidiary preferred interests, because that is the starting amount in the cash-flow statement.
| Profit-to-operating-cash bridge; first nine months 2026; USD millions | Amount |
|---|---|
| Consolidated net income | 1,012.175 |
| Add depreciation and amortization | 1,464.975 |
| Add Aquarion and offshore wind accounting charges | 305.360 |
| Add deferred income taxes | 240.333 |
| Add net regulatory over-recoveries | 372.765 |
| Other disclosed adjustments, net | 24.171 |
| Changes in current operating assets and liabilities, net | -351.472 |
| Operating cash flow | 3,068.307 |
“Other disclosed adjustments” consists of $61.747 million of uncollectible expense, minus $79.561 million of pension and other benefit-plan income, minus $164.638 million of asset-removal payments, plus $206.623 million of other adjustments. The current-account movement comprises $135.651 million from receivables and unbilled revenue, minus $38.067 million from tax balances, minus $205.924 million from accounts payable, and minus $243.132 million from other current balances. These names describe changes in when money is received or paid; they are not additional revenue or expense measures.
Deferred taxes reverse tax expense whose cash timing differs. Regulatory collections appear in both the over-recovery and amortization lines, so the $514.9 million decline discussed in Section 2 is not an extra subtraction from this bridge. Pension and construction-related accounting income also help explain why reported profit should not be treated as cash available for spending.
Opening cash, cash equivalents and restricted cash of $246.245 million, plus operating cash of $3,068.307 million, less investing outflows of $919.154 million and financing outflows of $1,800.015 million, equals closing cash on that basis of $595.383 million. Of that amount, $525.406 million was unrestricted cash and equivalents; the remaining $69.977 million was restricted. Restricted balances include bond-service funds, required deposits, escrow and nuclear-fuel-storage trusts.
The financing statement includes $2,679.894 million of long-term debt issuance, $2,006.803 million of long-term debt retirement and $1,525.445 million of short-term note repayment. Common shares provided $19.869 million after issuance costs. These flows, together with the investing receipt from Aquarion, explain how cash increased despite the allocation shortfall in Section 2.
Source: 2026 Form 10-Q, cash-flow statement, p. 5; Note 1G, pp. 21–22; MD&A, pp. 49–50.
C. Balance-sheet, equity and customer-credit checks
At September 30, 2026, liabilities excluding subsidiary preferred interests were $46,009.255 million. Adding $155.568 million of subsidiary preferred interests and $16,419.551 million of common equity gives $62,584.374 million, equal to assets. The same calculation at December 31, 2025 is $47,433.872 million plus $155.568 million plus $16,197.271 million, equaling $63,786.711 million.
Financing debt is calculated as notes payable plus both portions of ordinary debt and rate-reduction bonds. It fell from $30,114.898 million to $29,178.907 million. Subtracting unrestricted cash gives calculated net debt of $29,979.547 million and $28,653.501 million, respectively. Lease liabilities and contingent or regulatory obligations remain separate from this definition. PSNH’s rate-reduction bonds are payable from dedicated customer charges and are non-recourse to Eversource and PSNH.
| Common-equity accounts; USD millions | December 31, 2025 | Change | September 30, 2026 |
|---|---|---|---|
| Common-share capital | 1,914.3 | 1.4 | 1,915.7 |
| Additional paid-in capital | 9,937.9 | 78.8 | 10,016.7 |
| Retained earnings | 4,505.0 | 117.6 | 4,622.6 |
| Accumulated other comprehensive loss | -20.5 | 1.8 | -18.7 |
| Treasury shares, at recorded cost | -139.4 | 22.6 | -116.7 |
| Total common equity | 16,197.3 | 222.3 | 16,419.6 |
Retained earnings rose because roughly $1,006.5 million of profit attributable to common shareholders exceeded $888.9 million of common dividends recorded in equity. Only $871.3 million of those dividends was cash; $17.6 million was issued in treasury shares. Common-share capital, paid-in capital and the treasury-share account together increased by $102.9 million through new issuance, treasury-share releases, incentive-plan activity and issuance costs.
Paid-in capital records share-issuance value beyond the shares’ stated legal capital. Its $78.838 million increase reconciles $69.964 million from treasury-share releases, $19.102 million from new issuance, minus $9.550 million of net incentive-plan activity and $0.678 million of issuance costs.
The treasury-share account deducts the recorded cost of shares held by the company; releasing shares reduces that deduction. Other comprehensive income records specified changes outside net profit. It was $1.761 million, principally benefit-plan changes. Rounded equity figures may not add by $0.1 million; the filed quarterly entries also contain a $0.001 million difference from the cumulative preferred-interest figure.
The allowance for customer collection losses reconciles, in USD millions: opening $580.5 + expense $61.7 + costs deferred for regulatory recovery $103.6 − write-offs $167.2 + recoveries of previously written-off bills $12.1 − allowance removed with Aquarion $2.2 = closing $588.5. Deferring a loss for future collection in rates changes who is expected to pay; it does not mean the original customer paid the bill.
Source: 2026 Form 10-Q, pp. 1–3; Notes 1C, 7 and 13–15, pp. 19–20, 27–28 and 36–37.
D. Debt terms, leases and other exposures
The current portion of ordinary debt increased from $1,392.9 million to $2,875.2 million as the repayment horizon moved forward. For longer-term context, the last full annual schedule showed the following obligations. It is a December 2025 baseline, not an updated September 2026 forecast: subsequent issuance, repayments and the Aquarion disposal change its scope.
| Annual schedule at December 31, 2025; USD millions | 2026 | 2027 | 2028 | 2029 | 2030 |
|---|---|---|---|---|---|
| Ordinary debt principal maturities | 1,390.5 | 2,889.5 | 2,278.8 | 2,300.5 | 2,904.0 |
| Contractual interest on then-existing fixed-rate long-term debt | 1,214.9 | 1,153.1 | 1,041.4 | 919.7 | 828.8 |
The principal schedule excludes rate-reduction bonds, the specified spent-fuel obligation and debt accounting adjustments. The interest schedule multiplies contractual coupons by scheduled principal and does not include future refinancing. The February 2026 junior notes mature in August 2056. Their initial coupons are fixed until August 2031 and August 2036, respectively, then reset every five years to the applicable five-year Treasury rate plus 2.521 or 2.325 percentage points. The initial $93.375 million annual coupon calculation is $750 million × 6.10% + $750 million × 6.35%.
The annual filing limits debt as a share of debt plus other capital, using the agreement’s definitions. It specifies a maximum consolidated debt-to-capital ratio of 70% for Eversource and 65% for the other covered facility borrowers. It reports compliance at December 31, 2025. The quarterly filing reports no senior-security default but does not supply a fresh numerical covenant-headroom calculation. A breach could restrict new borrowing or require repayment, so unused credit capacity depends on continuing compliance.
At December 2025, minimum future lease payments, before adjusting for how far away the payment dates were, totaled $56.4 million for operating leases and $101.3 million for finance leases; their recorded liabilities after that timing adjustment were $47.4 million and $81.7 million. Those are historical consolidated amounts, including the then-owned water business. The third-quarter filing adds an EGMA property lease expected to start in 2027, with a $19.1 million agreement amount and a $19.3 million estimated purchase option considered likely to be exercised. Recognition begins when the lease starts. Leases are smaller than borrowing needs but remain additional contractual uses of cash.
Other disclosed exposures include $161.3 million of environmental reserves across 66 sites at September 30, up from $154.3 million at year-end. Much relates to former manufactured-gas sites; final remediation needs can change. The last full tax-risk disclosure reported $98.2 million of tax benefits not recognized because the tax positions were uncertain at December 2025, and an IRS audit of a 2022 partnership return. That historical tax amount is not presented as a September 2026 balance. These exposures remain relevant alongside the larger transmission and offshore wind issues, without assuming undisclosed additional losses.
Sources: 2025 Form 10-K, MD&A “Contractual Obligations,” p. 35; Notes 8–9, 12, 14 and 17, pp. 109, 113–114, 126–127, 136 and 138; 2026 Form 10-Q, Notes 9A and 9F, pp. 30 and 35; MD&A debt terms, p. 49; Part II, Item 3, p. 70.
This report is for general information and business analysis. It is not investment advice or a recommendation to buy or sell securities.