9 paragraphs in Risk Factors of the 10-K filed Feb 17, 2026
with nothing like them in the 10-K filed Feb 14, 2025. Quoted exactly.
Paragraphs that were only edited are under 10-K change.
Compared with the Risk Factors in the latest 10-K of the other 30 Utilities companies:
a paragraph with at least half its words the same at another company is called similar, and the companies are listed under it.
A paragraph most of them have is marked boilerplate. No line means no other company has one like it.
This counts text; it does not say how serious a risk is.
We are increasingly integrating artificial intelligence (AI) into our operations, and while these technologies offer operational benefits, they also introduce significant risks that could adversely impact our business and results of operations.
We deploy AI tools and models in areas such as weather forecasting, grid planning, asset management, customer service and internal support functions. This deployment is overseen by an internal governance and oversight committee, which has established policies and procedures and reviews and approves the use of AI throughout the organization. AI systems may produce inaccurate, biased or otherwise unreliable forecasts or recommendations due to flawed algorithms, limited training data or unforeseen conditions which could result in service disruptions, regulatory penalties and reputational harm. Evolving AI regulations may impose new compliance and reporting obligations or restrict usage and stakeholders may raise concerns about transparency, bias, and accountability. Despite implementing a governance framework and policies and controls in place related to AI use, including human oversight of critical decisions and outputs, these risks could negatively affect operations, expose us to litigation or regulatory penalties or fines, increase costs and impair our ability to meet customer expectations, which could have a material adverse impact on our financial position, results of operations, and cash flows.
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Our electric, natural gas, and water utility companies are subject to regulation by federal and state agencies and each is required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for service. Our regulated companies are entitled to charge rates that are sufficient to recover prudently incurred costs and a reasonable return on investment on invested capital. Regulatory decisions may require us to cancel, delay, or reduce planned investments or incur costs we cannot recover. Rates are subject to prudency reviews, refunds or disallowances and may not align with the timing of costs incurred. Adverse outcomes, including reductions in allowed rate of return, disallowance of costs or delays in rate adjustment, could adversely affect our financial position, results of operations and cash flows.
Customer affordability concerns, driven by volatility in energy supply costs, evolving public policy mandates and inflationary pressures, may limit our ability to recover costs or fund infrastructure upgrades. Regulators may respond by imposing stricter cost recovery standards, delaying or denying rate increases or cost recovery or requiring alternative funding mechanisms increasing financial uncertainty. Heightened political and public scrutiny of rate-setting processes may also lead to additional compliance obligations or reputational risk. These factors could adversely affect our financial position, results of operations and cash flows.
State commissions regulate rates, operations, accounting and certain financing activities. Rates are set in comprehensive base rate proceedings based on an analysis of invested capital, expenses and other factors, subject to periodic review and adjustments. Regulatory proceedings typically involve multiple parties who have differing concerns and can challenge our current or future rates, and these proceedings can be contentious, lengthy, and subject to appeal. This may lead to uncertainty as to the ultimate result of those proceedings.
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Regulatory approval is also required for certain dispositions of property and plant, mergers and consolidations and issuances of long-term securities, and construction and operation of facilities. Failure to obtain required approvals on a timely basis, or at all, could result in increased costs, the postponement or cancellation of planned transactions or projects, changes in financing strategies, and an adverse effect on our financial condition, results of operations, and ability to implement our business strategy.
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New processes and planning frameworks, including ISO-NE’s Longer-Term Transmission Planning (LTTP) competitive solicitation process and advisory role as asset condition reviewer, introduce uncertainty around project timing, scope and cost recovery. Competitive solicitations for certain transmission projects may require us to compete against non-incumbent developers, rather than relying on traditional cost-of-service recovery. Failure to secure projects through these processes could reduce transmission investment opportunities and associated incentives, adversely affecting our financial position, results of operations and cash flows.
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Our electric, natural gas and water utility subsidiaries serve large customer bases and are subject to adverse publicity regarding service safety, reliability and response times to outages, leaks or other interruptions, including those related to storms or climate change. Negative publicity can harm our reputation, influence legislative and regulatory bodies, and result in unfavorable outcomes, such as stricter operational standards, vegetation management requirements, fines, penalties or other sanctions.
We also depend on third-party suppliers for power and natural gas. Factors such as inflation, tariffs, geopolitical conflicts, rising energy demand, supply costs, and public policy charges contribute to high customer bills in New England. In extreme cases, ISO-NE may require load shed if regional power capacity is insufficient. High customer bills or failure to meet energy needs could reduce customer satisfaction adversely affecting our business, reputation, financial position, results of operations, and cash flows.
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New in the latest 10-Q
21 paragraphs in the 10-Q filed Nov 6, 2026 with nothing like
them in the 10-Q filed Aug 3, 2026 (at least half the words must differ; new numbers alone do not count).
Quoted exactly, grouped by the item heading above them. This is text that changed, not a judgement of how serious it is.
10-Q
(1) As part of the annual FERC Transmission Formula Rate protocols process, the AFUDC calculation methodology utilized in formula transmission rates was updated effective January 1, 2025. This calculation methodology resulted in an adjustment to the AFUDC equity and AFUDC debt amounts recognized on the statement of income in the third quarter of 2025 in accordance with the AFUDC policy.
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As part of the 2020 rate settlement approved by the DPU that enabled the acquisition of EGMA, the DPU required a rate base offset to be recorded, which would be amortized over time and be periodically adjusted in future rate filings for the build-up of deferred tax liabilities. The unamortized rate base offset is reflected as a reduction to Property, Plant and Equipment, Net on Eversource’s balance sheet. As of September 30, 2026, the rate base offset has been reduced by $ 40.0 million to reflect the build-up of the new deferred tax liabilities. The rate base offset reduction resulted in a reduction to depreciation expense on Eversource’s income statement in the third quarter of 2026. This benefit is presented within Eversource Parent and Other Companies in Note 17, “Segment Information,” consistent with past presentation of acquisition-related items.
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Eversource parent issued three guarantees in October 2026 on behalf of Revolution Wind TE Holdings, LLC. Eversource’s maximum exposure in connection with these guarantees is $ 972.0 million in order to support the sale of investment tax credits related to the Revolution Wind project.
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On April 20, 2026, the NETOs submitted to FERC a request for rehearing of Opinion No. 594 highlighting several deficiencies within the order. On May 21, 2026, FERC issued an order denying the request for rehearing by operation of law. On September 24, 2026, FERC issued its substantive order on rehearing, Opinion No. 594-A, addressing the merits of arguments raised by the NETOs and sustaining the result determined in Opinion No. 594.
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The Company’s estimates are based on currently available information. The Company has accrued $ 63.0 million as of September 30, 2026, representing the low end of the estimated range of probable liabilities. The Company continues to assess its legal position, the complexities associated with the refund calculation methodology, its extensive coordination with the NETOs and ISO-NE for the processing of long-dated refunds, and the timing of these required refunds. While the Company believes it has sound legal arguments challenging the March 2026 FERC decision, the ongoing refund calculation and developments in the refund process are expected to result in recording additional liabilities related to the retroactive refund period prior to the conclusion of the appellate proceeding. If there is no court or FERC action or further delay as a result of coordination with ISO-NE, then the Company will commence its refunds early in 2027 through the ISO-NE resettlement process. The Company expects to record a liability for the retroactive refund period as the refund calculations are finalized. Due to the uncertainties of the calculations described above, the refund amount for the retroactive period is not reasonably estimable as of September 30, 2026. The ultimate amount recognized may exceed the amount accrued by up to approximately $ 900 million and could have a material impact on the financial condition and results of operations.
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In the third quarter of 2026, EGMA entered into a land and building finance lease that is expected to commence in 2027. The lease contains a purchase option that the Company has determined is probable of being executed. In accordance with the accounting guidance for leases, the Company will recognize the right-of-use asset and corresponding lease liability, and will assess the purchase option as part of the lease fair value upon commencement. As of September 30, 2026, the lease agreement totaled $ 19.1 million and the estimated purchase option was $ 19.3 million.
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In the third quarter of 2026, as part of the 2025 tax return-to-provision process, Eversource recorded benefits associated with return true-ups of $ 41 million. The adjustment includes true-ups to state income taxes of $ 26 million as well as net operating loss carryforward adjustments of $ 15 million.
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In the third quarter of 2025, as part of filing its 2024 tax return-to-provision process, Eversource partially reversed a valuation allowance recorded on deferred tax assets associated with the loss recorded from the offshore wind investments and recorded a benefit of $ 165 million as it reconciled the positions on the tax return to what was estimated as of December 31, 2024. The adjustment to the valuation allowance was required based on the reconciling of previously recorded tax losses to amounts included in applicable partnership income tax returns. The adjustment resulted from changes in tax estimates based on information from the partnership tax returns received in the third quarter of 2025. Eversource also recognized state tax benefits and certain tax credits of $ 118 million as part of the 2024 tax return-to-provision process. These adjustments totaling $ 283 million were recorded as a reduction to income tax expense on the statement of income in the third quarter of 2025.
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Our water distribution segment earnings decreased $18.9 million in the third quarter of 2026, as compared to the third quarter of 2025, due to the absence of earnings in the third quarter of 2026 resulting from the June 30, 2026 sale of Aquarion.
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As part of the 2020 rate settlement approved by the DPU that enabled the acquisition of EGMA, the DPU required a rate base offset to be recorded, which would be amortized over time and be periodically adjusted in future rate filings for the build-up of deferred tax liabilities. The unamortized rate base offset is reflected as a reduction to Property, Plant and Equipment, Net on Eversource’s balance sheet. As of September 30, 2026, the rate base offset has been reduced by $40.0 million to reflect the build-up of the new deferred tax liabilities. The rate base offset reduction resulted in a reduction to depreciation expense on Eversource’s income statement in the third quarter of 2026. This benefit is presented within Eversource Parent and Other Companies, consistent with past presentation of acquisition-related items.
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On April 20, 2026, the NETOs submitted to FERC a request for rehearing of Opinion No. 594 highlighting several deficiencies within the order. On May 21, 2026, FERC issued an order denying the request for rehearing by operation of law. On September 24, 2026, FERC issued its substantive order on rehearing, Opinion No. 594-A, addressing the merits of arguments raised by the NETOs and sustaining the result determined in Opinion No. 594.
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The Company’s estimates are based on currently available information. The Company has accrued $63.0 million as of September 30, 2026, representing the low end of the estimated range of probable liabilities. The Company continues to assess its legal position, the complexities associated with the refund calculation methodology, its extensive coordination with the NETOs and ISO-NE for the processing of long-dated refunds, and the timing of these required refunds. While the Company believes it has sound legal arguments challenging the March 2026 FERC decision, the ongoing refund calculation and developments in the refund process are expected to result in recording additional liabilities related to the retroactive refund period prior to the conclusion of the appellate proceeding. If there is no court or FERC action or further delay as a result of coordination with ISO-NE, then the Company will commence its refunds early in 2027 through the ISO-NE resettlement process. The Company expects to record a liability for the retroactive refund period as the refund calculations are finalized. Due to the uncertainties of the calculations described above, the refund amount for the retroactive period is not reasonably estimable as of September 30, 2026. The ultimate amount recognized may exceed the amount accrued by up to approximately $900 million and could have a material impact on the financial condition and results of operations.
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If the FERC issues a final order eliminating the RTO ROE incentive as proposed in the CT RTO Adder Complaint, the estimated annual impact (using 2025 actual data) on Eversource’s after-tax earnings is approximately $12 million. We cannot predict the ultimate outcome of the regulatory or court complaints at this time.
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CL&P RAM Settlement: In connection with CL&P's 2021 Revenue Adjustment Mechanism (RAM) proceeding, PURA disallowed recovery through the Electric System Improvements (ESI) mechanism of certain storm-related capital investments. CL&P appealed PURA's decision to the Connecticut Superior Court and subsequently to the Connecticut Supreme Court. In May 2026, the Connecticut Supreme Court reversed the lower court's judgment and remanded the matter back to PURA.
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On September 21, 2026, CL&P and the Office of Consumer Counsel filed an amended settlement agreement with PURA in order to resolve issues associated with PURA's prior disallowance of certain storm-related capital investments included in CL&P's ESI mechanism. Under the proposed settlement, CL&P would recover approximately $8.2 million, representing 50 percent of the revenue requirement associated with the disputed investments through June 30, 2027, with the remaining 50 percent not recoverable from customers. Recovery of the approved amount would be collected through the ESI mechanism following PURA approval through June 30, 2027. Beginning July 1, 2027, the remaining approved unrecovered balance associated with the underlying investments would be recovered through base distribution rates. On November 4, 2026, PURA issued a proposed final decision that adopted the settlement agreement reached between CL&P and the Office of Consumer Counsel with no material modifications to the settlement’s terms. A final decision from PURA is expected by November 18, 2026.
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The variance in state-mandated charges for the three and nine month periods was also due to lower revenues from net metering at NSTAR Electric and lower transition revenues at PSNH reflecting the refund of RGGI over-recoveries to customers, partially offset by higher energy efficiency revenues at NSTAR Electric.
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The variance in Amortization for the three and nine month periods is partially offset by an increase in the stranded cost recovery mechanism at PSNH and the absence in 2026 of a benefit from the impact of the PSNH rate case decision in July 2025. The rate case decision allowed for the recoupment of temporary rates and the allowed recovery of other deferrals resulting in a pre-tax benefit to earnings of $15.6 million, the majority of which was recorded as a reduction to amortization expense on the statement of income in the third quarter of 2025.
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The variance in state-mandated charges for the nine month period was also due to lower revenues from net metering at NSTAR Electric and lower transition revenues at PSNH reflecting the refund of RGGI over-recoveries to customers, partially offset by higher energy efficiency revenues at NSTAR Electric.
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Other delivery: The increase in other delivery for the nine month period at CL&P is due to higher revenues from the capital tracking mechanism due to increased electric system improvements. At NSTAR Electric, the increase is due to the AMI capital tracking mechanism and the storm cost recovery mechanism, partially offset by the pension adjustment mechanism.
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Risk Factors
Although we have estimated a range of reasonably possible refund exposure and recorded a liability representing the low end of that range, additional losses significantly exceeding amounts currently recorded remain reasonably possible. As we continue to refine the refund calculation and coordinate the refund process with other New England transmission owners and ISO-NE, additional losses for the retroactive refund period may be recognized in future periods. Such losses would have a material adverse effect on our financial position, results of operations, liquidity and cash flows. Under the refund timing currently required by FERC, refunds will be required before completion of the appellate process, resulting in significant cash outflows prior to final judicial resolution. The calculation and processing of refunds involve significant complexity, are time-intensive, and require coordination among the NETOs and ISO-NE, which may affect the amount and timing of refunds. Additionally, the methodologies and conclusions reflected in the FERC order may influence future transmission ROE proceedings and could result in lower authorized returns on existing and future transmission investments.
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See "FERC Regulatory Matters - FERC ROE Complaints," in the accompanying Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 9C, “Commitments and Contingencies - FERC ROE Complaints,” to the financial statements for additional information regarding the financial impact of this order.
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The 10-Q's risk factors against the 10-K
Item 1A of the 10-Q filed Nov 6, 2026 against Item 1A of the 10-K filed Feb 17, 2026.
A 10-Q repeats only the risks that changed, so a 10-K paragraph that is missing from it is not counted as removed.
Added is a paragraph with nothing like it in the 10-K, Reworded a sentence that is in both with several words changed,
Quiet changes a sentence in both where one to four words changed and one is a hedge or a modal
(cut words struck through, new words highlighted and underlined).
Text on the page, not a score; each links to the filing at sec.gov.
What the 10-Q itself says about its risk factors:
Other than as set forth above, there have been no additional risk factors identified and no material changes with regard to the risk factors previously disclosed in our 2025 Form 10-K.
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Added10-Q 2026-11-06 vs 10-K 2026-02-17
We are subject to a variety of significant risks in addition to the matters set forth under our forward-looking statements section in Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations," of this Quarterly Report on Form 10-Q. We have identified a number of these risk factors in Part I, Item 1A, "Risk Factors," in our 2025 Form 10-K, which risk factors are incorporated herein by reference. These risk factors should be considered carefully in evaluating our risk profile. The following risk factor update should be read in conjunction with the risk factors described in the 2025 Form 10-K.
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Added10-Q 2026-11-06 vs 10-K 2026-02-17
Eversource and other transmission-owning electric companies within ISO-NE have been subject to complaints challenging the reasonableness of our allowed ROEs since 2011. On March 19, 2026, FERC issued an order finding that the base ROE was unjust and unreasonable and setting a new base ROE for the first complaint period and prospectively from October 2014. FERC ordered refunds with interest for those historical refund periods, which are material to us, and dismissed the other three complaints. The material amount of the refunds required by FERC’s order is driven primarily by the length of the retroactive refund period, which spans nearly 12 years. Application of the revised base ROE to revenues collected over this extended historical period substantially increased the aggregate refund obligation compared to what would have resulted from a shorter refund period. The order adversely affects our financial position, results of operations, liquidity, and cash flows. Eversource has appealed the FERC order, however, there can be no assurance that the appeal will result in modification or reversal of the FERC order, and we cannot predict the ultimate outcome of this proceeding or its timing.
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Added10-Q 2026-11-06 vs 10-K 2026-02-17
Although we have estimated a range of reasonably possible refund exposure and recorded a liability representing the low end of that range, additional losses significantly exceeding amounts currently recorded remain reasonably possible. As we continue to refine the refund calculation and coordinate the refund process with other New England transmission owners and ISO-NE, additional losses for the retroactive refund period may be recognized in future periods. Such losses would have a material adverse effect on our financial position, results of operations, liquidity and cash flows. Under the refund timing currently required by FERC, refunds will be required before completion of the appellate process, resulting in significant cash outflows prior to final judicial resolution. The calculation and processing of refunds involve significant complexity, are time-intensive, and require coordination among the NETOs and ISO-NE, which may affect the amount and timing of refunds. Additionally, the methodologies and conclusions reflected in the FERC order may influence future transmission ROE proceedings and could result in lower authorized returns on existing and future transmission investments.
Read it in the 10-Q at sec.gov ↗
Added10-Q 2026-11-06 vs 10-K 2026-02-17
See "FERC Regulatory Matters - FERC ROE Complaints," in the accompanying Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 9C, “Commitments and Contingencies - FERC ROE Complaints,” to the financial statements for additional information regarding the financial impact of this order.
Read it in the 10-Q at sec.gov ↗
