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Regulatory Matters | 12 Months Ended
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Dec. 31, 2025
Regulated Operations [Abstract] |
Regulatory Matters | REGULATORY MATTERS REGULATORY ASSETS AND LIABILITIES The Duke Energy Registrants record regulatory assets and liabilities that result from the ratemaking process. See Note 1 for further information. The following tables present the regulatory assets and liabilities recorded on the Consolidated Balance Sheets of Duke Energy and Progress Energy. See separate tables below for balances by individual registrant.
| Duke Energy |  | Progress Energy |  |  |  |  |  |  |  |  |  |  |  |  |  |
| December 31, |  | December 31, |  |  |  |  |  |  |  |  |  |  |  |  |  |
(in millions) | 2025 |  | 2024 |  | 2025 |  | 2024 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Regulatory Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
AROs – coal ash | $ | 3,670 |  |  | $ | 3,384 |  |  | $ | 1,544 |  |  | $ | 1,335 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Accrued pension and OPEB | 2,281 |  |  | 2,524 |  |  | 744 |  |  | 828 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Storm cost deferrals | 73 |  |  | 1,951 |  |  | 49 |  |  | 1,238 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Storm cost securitized balance, net | 2,567 |  |  | 1,023 |  |  | 1,239 |  |  | 822 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
AROs – nuclear and other | 602 |  |  | 948 |  |  | 564 |  |  | 905 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Nuclear asset securitized balance, net | 717 |  |  | 771 |  |  | 717 |  |  | 771 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Debt fair value adjustment | 665 |  |  | 719 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
COR regulatory asset | 860 |  |  | 646 |  |  | 746 |  |  | 571 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred fuel and purchased power | 619 |  |  | 588 |  |  | 228 |  |  | 282 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Hedge costs deferrals | 365 |  |  | 352 |  |  | 135 |  |  | 126 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
PISCC and deferred operating expenses | 291 |  |  | 331 |  |  | 37 |  |  | 37 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Retired generation facilities | 252 |  |  | 337 |  |  | 176 |  |  | 202 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Customer connect project | 234 |  |  | 257 |  |  | 107 |  |  | 116 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Grid deferral | 257 |  |  | 255 |  |  | 63 |  |  | 54 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Incremental COVID-19 expenses | 202 |  |  | 231 |  |  | 94 |  |  | 89 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Vacation accrual | 240 |  |  | 228 |  |  | 45 |  |  | 43 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred asset – Lee and Harris COLA | 177 |  |  | 215 |  |  | 4 |  |  | 10 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Advanced metering infrastructure (AMI) | 162 |  |  | 204 |  |  | 48 |  |  | 70 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Demand side management (DSM) / Energy efficiency (EE) | 335 |  |  | 199 |  |  | 247 |  |  | 199 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
CEP deferral | 200 |  |  | 195 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NCEMPA deferrals | 202 |  |  | 179 |  |  | 202 |  |  | 179 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Decoupling | 118 |  |  | 162 |  |  | 27 |  |  | 32 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Nuclear deferral | 117 |  |  | 134 |  |  | 53 |  |  | 53 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred pipeline integrity costs | 117 |  |  | 129 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
COR settlement | 106 |  |  | 110 |  |  | 28 |  |  | 29 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Derivatives – natural gas supply contracts | 72 |  |  | 94 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred coal ash handling system costs | 60 |  |  | 77 |  |  | 13 |  |  | 17 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Qualifying facility contract buyouts | 55 |  |  | 62 |  |  | 55 |  |  | 62 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Network Integration Transmission Services deferral | 31 |  |  | 31 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Transmission expansion obligation | 30 |  |  | 31 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
East Bend deferrals | 20 |  |  | 24 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Propane caverns | 22 |  |  | 24 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred purchased gas costs | 26 |  |  | 9 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other | 568 |  |  | 535 |  |  | 238 |  |  | 195 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total regulatory assets | 16,313 |  |  | 16,959 |  |  | 7,403 |  |  | 8,265 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Less: Current portion | 1,934 |  |  | 2,739 |  |  | 753 |  |  | 1,647 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total noncurrent regulatory assets | $ | 14,379 |  |  | $ | 14,220 |  |  | $ | 6,650 |  |  | $ | 6,618 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Regulatory Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
COR regulatory liability | $ | 5,336 |  |  | $ | 5,302 |  |  | $ | 3,084 |  |  | $ | 2,984 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net regulatory liability related to income taxes | 4,748 |  |  | 5,356 |  |  | 1,741 |  |  | 1,882 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
AROs – nuclear and other | 2,982 |  |  | 2,289 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred nuclear PTC | 1,377 |  |  | 676 |  |  | 197 |  |  | 95 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Hedge cost deferrals | 582 |  |  | 583 |  |  | 248 |  |  | 281 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Renewable energy credits | 267 |  |  | 241 |  |  | 146 |  |  | 139 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Accrued pension and OPEB | 184 |  |  | 232 |  |  | 11 |  |  | 12 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred fuel and purchased power | 28 |  |  | 223 |  |  | 28 |  |  | 94 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Storm cost recovery | 262 |  |  | 6 |  |  | 90 |  |  | 6 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
DSM / EE | 26 |  |  | 69 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Storm reserve | 132 |  |  | — |  |  | 132 |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Nuclear insurance distributions reserve | 163 |  |  | 152 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other | 866 |  |  | 813 |  |  | 274 |  |  | 287 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total regulatory liabilities | 16,953 |  |  | 15,942 |  |  | 5,951 |  |  | 5,780 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Less: Current portion | 1,271 |  |  | 1,421 |  |  | 350 |  |  | 522 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total noncurrent regulatory liabilities | $ | 15,682 |  |  | $ | 14,521 |  |  | $ | 5,601 |  |  | $ | 5,258 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Descriptions of regulatory assets and liabilities summarized in the tables above and below follow. See tables below for recovery and amortization periods at the separate registrants. AROs – coal ash. Represents deferred depreciation and accretion related to the legal obligation to close ash basins. The costs are deferred until recovery treatment has been determined. See Notes 1 and 10 for additional information. AROs – nuclear and other. Represents regulatory assets or liabilities, including deferred depreciation and accretion, related to legal obligations associated with the future retirement of property, plant and equipment, excluding amounts related to coal ash. The AROs relate primarily to decommissioning nuclear power facilities. The amounts also include certain deferred gains and losses on NDTF investments. See Notes 1 and 10 for additional information. Deferred fuel and purchased power. Represents certain energy-related costs that are recoverable or refundable as approved by the applicable regulatory body. Accrued pension and OPEB. Accrued pension and OPEB represent regulatory assets and liabilities related to each of the Duke Energy Registrants’ respective shares of unrecognized actuarial gains and losses and unrecognized prior service cost and credit attributable to Duke Energy’s pension plans and OPEB plans. The regulatory asset or liability is amortized with the recognition of actuarial gains and losses and prior service cost and credit to net periodic benefit costs for pension and OPEB plans. The accrued pension and OPEB regulatory assets are expected to be recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail. Storm cost deferrals. Represents deferred incremental costs incurred related to major weather-related events. Storm cost securitized balance, net. Represents the North Carolina portion of storm restoration expenditures related to hurricanes Helene, Debby, Ian, Florence, Michael, Dorian and Zeta and winter storms Diego and Izzy. The South Carolina portion of storm restoration expenditures are related to ice storms Pax and Ulysses, hurricanes Helene, Matthew, Florence, Michael and Dorian and Winter Storms Izzy and Jasper, as well as funding of the negative South Carolina storm reserve balance. Nuclear asset securitized balance, net. Represents the balance associated with Crystal River Unit 3 retirement approved for recovery by the FPSC on September 15, 2015, and the upfront financing costs securitized in 2016 with issuance of the associated bonds. The regulatory asset balance is net of the AFUDC equity portion. Debt fair value adjustment. Purchase accounting adjustments recorded at the Duke Energy (Parent) level to state the carrying value of debt at fair value in connection with the Duke Energy mergers with Progress Energy in 2012 and Piedmont in 2016. Amount is amortized over the life of the related debt. Hedge costs deferrals. Amounts relate to realized and unrealized gains and losses on derivatives recorded as a regulatory asset or liability, respectively, until the contracts are settled. COR regulatory asset. Represents the excess of spend over funds received from customers to cover the future removal of property, plant and equipment from retired or abandoned sites as property is retired, net of certain deferred gains on NDTF investments. PISCC and deferred operating expenses. Represents deferred depreciation and operating expenses as well as carrying costs on the portion of capital expenditures placed in service but not yet reflected in retail rates as plant in service. Retired generation facilities. Represents amounts to be recovered for facilities that have been retired and are probable of recovery. Deferred asset – Lee and Harris COLA. Represents deferred costs incurred for the canceled Lee and Harris nuclear projects. Customer connect project. Represents incremental operating expenses and carrying costs on deferred amounts related to the deployment of the new customer information system. AMI. Represents deferred costs related to the installation of AMI meters and remaining net book value of non-AMI meters to be replaced at Duke Energy Carolinas, net book value of existing meters at Duke Energy Florida, Duke Energy Progress and Duke Energy Ohio and future recovery of net book value of electromechanical meters that have been replaced with AMI meters at Duke Energy Indiana. Incremental COVID-19 expenses. Represents incremental costs related to customer charge-offs and certain costs to ensure continuity and quality of service in a safe manner during the COVID-19 pandemic. Vacation accrual. Represents vacation entitlement, which is generally recovered in the following year. Grid deferral. Represents deferred incremental operation and maintenance expense, depreciation and property taxes associated with grid improvement plans. DSM/EE. Deferred costs related to various DSM and EE programs recoverable or refundable as approved by the applicable regulatory body. CEP deferral. Represents deferred depreciation, PISCC and deferred property tax for Duke Energy Ohio Gas capital assets for the CEP. NCEMPA deferrals. Represents retail allocated cost deferrals and returns associated with the additional ownership interest in assets acquired from NCEMPA in 2015. Derivatives – natural gas supply contracts. Represents costs for certain long-dated, fixed quantity forward natural gas supply contracts, which are recoverable through PGA clauses. Deferred pipeline integrity costs. Represents pipeline integrity management costs in compliance with federal regulations. Nuclear deferral. Includes amounts related to nuclear plant outage and refueling costs, which are deferred and recovered over the nuclear fuel cycle. COR settlement. Represents approved COR settlements that are being amortized over the average remaining lives, at the time of approval, of the associated assets. Decoupling. Relates primarily to margin and revenue decoupling. Deferred coal ash handling system costs. Represents deferred depreciation and returns associated with capital assets related to converting the ash handling system from wet to dry. Qualifying facility contract buyouts. Represents termination payments for regulatory recovery through the capacity clause. Network Integration Transmission Services deferral. Represents a deferral of costs and return related transmission costs. Transmission expansion obligation. Represents transmission expansion obligations related to Duke Energy Ohio's withdrawal from MISO. East Bend deferrals. Represents amounts to be recovered for deferred costs and depreciation related to the East Bend station. Propane caverns. Represents amounts for costs related to propane inventory, the net book value of remaining assets and decommissioning costs at Duke Energy Ohio. Net regulatory liability related to income taxes. Amounts for all registrants include regulatory liabilities related primarily to impacts from the Tax Cuts and Jobs Act (the Tax Act). See Note 24 for additional information. Amounts have no immediate impact on rate base as regulatory assets are offset by deferred tax liabilities. COR regulatory liability. Represents funds received from customers to cover current and future coal ash remediation costs and future removal of property, plant and equipment from retired or abandoned sites as property is retired. Also includes certain deferred gains on NDTF investments. Deferred nuclear PTC. Represents the net realizable value of nuclear PTCs that will be passed back to customers over time. Renewable energy credits. Represents certificates for the environmental benefits of renewable energy that will be returned to customers in a future period. Storm cost recovery. Actual storm costs were less than the amount securitized and the difference is deferred as a regulatory liability and accrues a return at the commission-authorized WACC from the bond issuance date until the amount is reflected in customer rates. Storm reserve. Amounts reserved for future incremental storm restoration costs. Nuclear insurance distributions reserve. Amounts reserved related to the Nuclear Mutual Limited (now known as Nuclear Electric Insurance Limited (NEIL)) portion of nuclear insurance distributions which are to be held for the benefit of customers. Deferred purchased gas costs. Represents certain natural gas costs that are recoverable or refundable as approved by the applicable regulatory body. RESTRICTIONS ON THE ABILITY OF CERTAIN SUBSIDIARIES TO MAKE DIVIDENDS, ADVANCES AND LOANS TO DUKE ENERGY As a condition to the approval of merger transactions, the NCUC, PSCSC, PUCO, KPSC and IURC imposed conditions on the ability of Duke Energy Carolinas, Duke Energy Progress, Duke Energy Ohio, Duke Energy Kentucky, Duke Energy Indiana and Piedmont to transfer funds to Duke Energy through loans or advances, as well as restricted amounts available to pay dividends to Duke Energy. Certain subsidiaries may transfer funds to the Parent by obtaining approval of the respective state regulatory commissions. These conditions imposed restrictions on the ability of the public utility subsidiaries to pay cash dividends as discussed below. Duke Energy Progress and Duke Energy Florida also have restrictions imposed by their first mortgage bond indentures, which in certain circumstances, limit their ability to make cash dividends or distributions on common stock. Amounts restricted as a result of these provisions were not material at December 31, 2025. Additionally, certain other subsidiaries of Duke Energy have restrictions on their ability to dividend, loan or advance funds to Duke Energy due to specific legal or regulatory restrictions, including, but not limited to, minimum working capital and tangible net worth requirements. The restrictions discussed below were not a material amount of Duke Energy's and Progress Energy's net assets at December 31, 2025. Duke Energy Carolinas Duke Energy Carolinas must limit cumulative distributions subsequent to mergers to (i) the amount of retained earnings on the day prior to the closing of the mergers, plus (ii) any future earnings recorded. Duke Energy Progress Duke Energy Progress must limit cumulative distributions subsequent to the mergers between Duke Energy and Progress Energy and Duke Energy and Piedmont to (i) the amount of retained earnings on the day prior to the closing of the respective mergers, plus (ii) any future earnings recorded. Duke Energy Ohio Duke Energy Ohio will not declare and pay dividends out of capital or unearned surplus without the prior authorization of the PUCO. Duke Energy Ohio received FERC and PUCO approval to pay dividends from its equity accounts that are reflective of the amount that it would have in its retained earnings account had push-down accounting for the Cinergy merger not been applied to Duke Energy Ohio’s balance sheet. The conditions include a commitment from Duke Energy Ohio that equity, adjusted to remove the impacts of push-down accounting, will not fall below 30% of total capital. Duke Energy Kentucky is required to pay dividends solely out of retained earnings and to maintain a minimum of 35% equity in its capital structure. Duke Energy Indiana Duke Energy Indiana must limit cumulative distributions subsequent to the merger between Duke Energy and Cinergy to (i) the amount of retained earnings on the day prior to the closing of the merger, plus (ii) any future earnings recorded. In addition, Duke Energy Indiana will not declare and pay dividends out of capital or unearned surplus without prior authorization of the IURC. Piedmont Piedmont must limit cumulative distributions subsequent to the acquisition of Piedmont by Duke Energy to (i) the amount of retained earnings on the day prior to the closing of the merger, plus (ii) any future earnings recorded. RATE-RELATED INFORMATION The NCUC, PSCSC, FPSC, IURC, PUCO, TPUC and KPSC approve rates for retail electric and natural gas services within their states. The FERC approves rates for electric sales to wholesale customers served under cost-based rates (excluding Ohio and Indiana), as well as sales of transmission service. For open regulatory matters, unless otherwise noted, the Subsidiary Registrants and Duke Energy Kentucky cannot predict the outcome or ultimate resolution of their respective matters. Winter Storm Fern In late January 2026, Winter Storm Fern moved across the eastern U.S and impacted all of Duke Energy's service territories, with damage primarily occurring in the Duke Energy Carolinas and Duke Energy Progress territories in North Carolina and South Carolina. Approximately 200,000 customers were impacted across Duke Energy's system. Total storm restoration costs, including capital expenditures, for Duke Energy are currently estimated to be in the range of $250 million to $350 million (which includes $150 million to $225 million for Duke Energy Carolinas and $100 million to $125 million for Duke Energy Progress). Incremental storm restoration costs related to operation and maintenance activities in excess of amounts in base rates will be deferred as regulatory assets and reviewed for recovery in future regulatory proceedings or charged to storm reserves, where applicable. These estimates could change as additional information is received on actual costs incurred for preparation and restoration activities. Duke Energy Carolinas and Duke Energy Progress Hurricanes Debby and Helene In 2024, hurricanes Debby and Helene significantly impacted the Duke Energy Carolinas and Duke Energy Progress territories in North Carolina and South Carolina. As of December 31, 2025, total cumulative operations and maintenance expenses incurred for restoration and rebuilding of infrastructure were approximately $762 million ($474 million and $288 million for Duke Energy Carolinas and Duke Energy Progress, respectively), with an additional $507 million in cumulative capital investments ($408 million and $99 million for Duke Energy Carolinas and Duke Energy Progress, respectively), net of expected insurance recovery. The operations and maintenance expense amounts were deferred in Regulatory assets within Other Noncurrent Assets on the Consolidated Balance Sheets when incurred. Substantially all of the storm related costs have been securitized for recovery in both North Carolina and South Carolina as of December 31, 2025, as described below. North Carolina Storm Cost Securitization In December 2024, Duke Energy Carolinas and Duke Energy Progress filed their joint petition for review and approval of storm recovery costs (Phase 1) with the NCUC to securitize the North Carolina-retail allocable share of storm costs associated with hurricanes Helene, Debby and Ian, as well as Hurricane Zeta and Winter Storm Izzy, and the establishment of storm reserves for $200 million at Duke Energy Carolinas and $100 million at Duke Energy Progress. On February 3, 2025, Duke Energy Carolinas and Duke Energy Progress filed their joint petition for financing orders (Phase 2). Duke Energy Carolinas and Duke Energy Progress reached settlement agreements with the North Carolina Public Staff and other intervening parties that resolved all issues in the Phase 1 and Phase 2 proceedings and removed the establishment of storm reserves from the securitization proceeding. On April 16, 2025, the NCUC issued its Phase 1 order approving the settlement and determining storm recovery costs were reasonable, prudent and eligible for securitization. On June 18, 2025, the NCUC issued its Phase 2 order approving the settlement and issuing the financing orders. In September 2025, Duke Energy Carolinas and Duke Energy Prog ress issued $582 million and $461 million, respectively, of storm recovery bonds. Storm recovery charges were effective November 1, 2025. Per the financing orders, any differences between estimates and actual costs of the storms must be accumulated and tracked to allow for a detailed review of the costs for reasonableness and prudency in Duke Energy Carolinas' and Duke Energy Progress’ next general rate case proceedings. As of December 31, 2025, actual North Carolina-retail allocable storm costs were lower than estimates and Duke Energy Carolinas and Duke Energy Progress recorded $136 million and $71 million, respectively, in Regulatory Liabilities within Other Noncurrent Liabilities on the Consolidated Balance Sheets. Accordingly, these amounts were included in Duke Energy Carolinas' and Duke Energy Progress' PBR applications filed in November 2025. See below and Notes 7 and 18 for more information. South Carolina Storm Cost Securitization On March 21, 2025, Duke Energy Carolinas filed a petition for storm securitization with the PSCSC for authorization to finance the estimated South Carolina-retail allocable share of storm costs primarily related to Hurricane Helene storm recovery activities and inclusive of funding $25 million related to storm reserves. Duke Energy Carolinas reached a comprehensive settlement among all parties in the proceeding, which was filed with the PSCSC supporting securitization, including the storm reserve funding. On July 10, 2025, the PSCSC approved the settlement and the financing orde r was issued on August 1, 2025. In November 2025, Duke Energy Carolinas issued $561 million of storm recovery bonds. See Notes 7 and 18 for more information. Storm recovery charges were effective January 1, 2026. Additionally, per the financing order, any differences between estimates and actual costs of the storms must be accumulated and tracked to allow for a detailed review of the costs for reasonableness and prudency in Duke Energy Carolinas' next general rate case proceeding. As of December 31, 2025, actual South Carolina-retail allocable storm costs were lower than estimates and Duke Energy Carolinas recorded $35 million in Regulatory Liabilities within Other Noncurrent Liabilities on the Consolidated Balance Sheets. Due to the relatively low level of storm costs incurred by Duke Energy Progress in South Carolina, Duke Energy Progress will not seek to pursue securitization of those costs and has offset them against established storm reserve balances. Applications to Combine Utilities On August 14, 2025, Duke Energy Carolinas and Duke Energy Progress (together, the Companies) filed a joint application with the NCUC and PSCSC for approval to combine utilities, by which Duke Energy Progress will merge into Duke Energy Carolinas, resulting in a single electric utility serving the Companies' North Carolina and S outh Carolina service territories. Duke Energy Corporation, together with the Companies, also filed an application with the FERC on the same day. The single utility’s ability to plan, execute, and operate resources more efficiently is expected to result in substantial cost savings, benefiting customers by reducing the overall costs to serve. Subject to regulatory approvals, the targeted effective date is January 1, 2027. On January 30, 2026, FERC issued an order authorizing the combination as consistent with the public interest. There is no assurance that Duke Energy, Duke Energy Carolinas and Duke Energy Progress will obtain required regulatory approvals from the NCUC and the PSCSC, and approvals from all three regulators are required for the transaction to proceed. The North Carolina Public Staff and intervenors in the NCUC proceeding filed testimony advocating, in part, that the NCUC impose certain conditions for the combination to go forward, including conditions related to treatment of costs to achieve and future rate consolidat ion. In th e South Carolina proceeding, the South Carolina Office of Regulatory Staff and intervenors filed testimony recommending that the PSCSC condition approval of the combination on additional requirements, including addressing the identification, allocation and recovery of cost impacts and costs to achieve, as well as the treatment of benefits. On February 24, 2026, the Companies reached a comprehensive settlement with th e North Carolina P ublic Staff and certain other intervenors (stipulating parties) in the case, which was filed with NCU C. Subject to approval by the NCUC, the agreement resolves all issues betwee n the stipulating parties reg arding the combination of Duke Energy Carolinas and Duke Energy Progress. Among other terms, the agreement requires the Companies to guarantee savings from the combination will be at least $286 million to North Carolina retail customers over a 14-year period, permits recovery and deferral of costs to achieve, removes 200 MW of battery storage from th e recommended portfolio and near term action plan in the 2025 Carolinas Resource Plan and provides that North Carolinas retail customers should provide an annual $25 million of Share the Benefits Contributions to South Carolina retail customers for six years starting in 2030. The evidentiary hearing before the NCUC commenced on February 25, 2026. The South Carolina evidentiary hearing is anticipated to begin on April 8, 2026. Both orders are anticipated to be issued in the second quarter of 2026. Duke Energy Carolinas Regulatory Assets and Liabilities The following tables present the regulatory assets and liabilities recorded on Duke Energy Carolinas' Consolidated Balance Sheets.
| December 31, |  | Earns/Pays | Recovery/Refund
(in millions) | 2025 | 2024 |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
AROs – coal ash | $ | 1,506 |  | $ | 1,481 |  |  | Yes | (b)
Storm cost deferrals | — |  | 691 |  |  | Yes | (b)
Accrued pension and OPEB(c) | 592 |  | 668 |  |  | Yes | (g)
Deferred fuel and purchased power | 306 |  | 298 |  |  | (e) | 2028
Deferred asset – Lee COLA | 173 |  | 205 |  |  |  | (b)
Hedge costs deferrals | 199 |  | 202 |  |  |  | (b)
Storm cost securitized balance, net | 1,328 |  | 201 |  |  |  | 2046
Grid deferral(c) | 194 |  | 201 |  |  | Yes | (b)
Incremental COVID-19 expenses(c) | 104 |  | 137 |  |  | Yes | (b)
AMI(c) | 102 |  | 114 |  |  | Yes | (b)
Vacation accrual | 91 |  | 86 |  |  |  | 2026
Nuclear deferral | 64 |  | 81 |  |  |  | 2027
COR settlement | 78 |  | 81 |  |  | Yes | (b)
Deferred coal ash handling system costs(c) | 47 |  | 60 |  |  | Yes | (b)
Customer connect project(c) | 48 |  | 54 |  |  | Yes | (b)
Retired generation facilities(c) | 56 |  | 110 |  |  | Yes | (b)
DSM/EE | 86 |  | — |  |  | Yes | (h)
PISCC and deferred operating expenses | 39 |  | 42 |  |  | Yes | (b)
Decoupling | 45 |  | 24 |  |  | Yes | (b)
Other | 174 |  | 148 |  |  |  | (b)
Total regulatory assets | 5,232 |  | 4,884 |  |  |  |
Less: Current portion | 730 |  | 685 |  |  |  |
Total noncurrent regulatory assets | $ | 4,502 |  | $ | 4,199 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
AROs – nuclear and other | $ | 2,982 |  | 2,289 |  |  |  | (b)
Net regulatory liability related to income taxes(d) | 1,608 |  | $ | 1,951 |  |  | Yes | (b)
COR regulatory liability(c) | 1,383 |  | 1,479 |  |  |  | (f)
Deferred nuclear PTC | 1,180 |  | 581 |  |  | Yes | (b)
Hedge cost deferrals | 228 |  | 199 |  |  |  | (b)
Deferred fuel and purchased power | — |  | 108 |  |  | (e) |
Renewable energy credits | 121 |  | 102 |  |  | Yes | (b)
Storm cost recovery | 172 |  | — |  |  | Yes | (b)
DSM / EE(c) | — |  | 53 |  |  | Yes | (h)
Accrued pension and OPEB(c) | 18 |  | 35 |  |  | Yes | (g)
Nuclear insurance distributions reserve(c) | 163 |  | 152 |  |  | Yes | (b)
Other | 323 |  | 261 |  |  |  | (b)
Total regulatory liabilities | 8,178 |  | 7,210 |  |  |  |
Less: Current portion | 569 |  | 618 |  |  |  |
Total noncurrent regulatory liabilities | $ | 7,609 |  | $ | 6,592 |  |  |  |
(a) Regulatory assets and liabilities are excluded from rate base unless otherwise noted. (b) The expected recovery or refund period varies or has not been determined. (c) Included in rate base. (d) Includes regulatory liabilities related to the change in the federal tax rate as a result of the Tax Act and the change in the North Carolina tax rate. Portions are included in rate base. (e) Pays interest on over-recovered costs in North Carolina. Includes certain purchased power costs in North Carolina and South Carolina and costs of distributed energy in South Carolina. The asset balance principally relates to North Carolina costs while the liability balance relates to South Carolina. (f) Recovered over the life of the associated assets. (g) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail. (h) Includes incentives on DSM/EE investments and is recovered or refunded through an annual rider mechanism. 2023 North Carolina Rate Case In January 2023, Duke Energy Carolinas filed a PBR application with the NCUC to request an increase in base rate retail revenues. The PBR application included an MYRP to recover projected capital investments during the three-year MYRP period. In addition to the MYRP, the PBR application included an Earnings Sharing Mechanism, Residential Decoupling Mechanism and Performance Incentive Mechanisms (PIMs) as required by HB951. In August 2023, Duke Energy Carolinas filed with the NCUC a partial settlement with the North Carolina Public Staff in connection with its PBR application. The partial settlement included, among other things, a greement on a substantial portion of the North Carolina retail rate base for the historic base case of approximately $19.5 billion and all of the capital projects and related costs to be included in the three-year MYRP, including $4.6 billion (North Carolina retail allocation) projected to go in service over the MYRP period. Additionally, the partial settlement included agreement, with certain adjustments, on depreciation rates, the recovery of grid improvement plan costs and PIMs, Tracking Metrics and the Residential Decoupling Mechanism under t he PBR application. On August 28, 2023, Duke Energy Carolinas filed with the NCUC a second partial settlement with the North Carolina Public Staff resolving additional issues, including the future treatment of nuclear PTCs related to the IRA, through a stand-alone rider that would provide the benefits to customers. This stand-alone rider was effective in rates beginning January 1, 2025. On December 1 5, 2023, the NCUC issued an order approving Duke Energy Carolinas' PBR application, as modified by the partial settlements and the order, including an overall retail revenue increase of $436 million in Year 1, $174 million in Year 2 and $158 million in Year 3, for a combined total of $768 million. T he order established an ROE of 10.1% based upon an equity ratio of 53% and approved, with certain adjustments, depreciation rates and the recovery of grid improvement plan costs and certain deferred COV ID-related costs. Additionally, the Residential Decoupling Mechanism and PIMs were approved as requested under the PBR application and revised by the partial settlements. As a result of the partial settlements and the order, Duke Energy Carolinas recognized pretax charges of $29 million within Impairment of assets and other charges, and $8 million within Operations, maintenance and other, for the year ended December 31, 2023, on the Consolidated Statements of Operations. Duke Energy Carolinas implemented interim rates on September 1, 2023. New revised Year 1 rates and the residential decoupling were implemented on January 15, 2024. In February 2024, a number of parties filed Notices of Appeal of the December 15, 2023 NCUC order. Notices of Appeal were filed by the Carolina Industrial Group for Fair Utility Rates (CIGFUR) III, a collection of electric membership cooperatives (collectively, the EMCs), and the North Carolina Attorney General’s Office (the AGO). CIGFUR III and the EMCs appealed the interclass subsidy reduction percentage and the Transmission Cost Allocation stipulation. In addition, CIGFUR III appealed the NCUC’s elimination of the equal percentage fuel cost allocation methodology. The AGO appealed several issues including the authorized ROE and certain rate design and accounting matters. On March 1, 2024, Carolina Utility Customers Association, Inc. appealed several issues, including the authorized ROE and certain rate design and accounting matters. In July 2024, the Supreme Court of North Carolina c onsolidated these appeals with the parallel appeals of the NCUC's order regarding the Duke Energy Progress PBR application. Briefing is complete and oral arguments occurred in February 2025. Duke Energy Carolinas anticipates a decisi on to be issued in the first half of 2026. 2025 North Carolina Rate Case On November 20, 2025, Duke Energy Carolinas filed a PBR application with the NCUC to request an increase i n base rate retail revenues. The PBR application includes an MYRP to recover projected capital investments during a two-year MYRP period. In addition to the MYRP, the PBR application includes an Earnings Sharing Mechanism, Residential Decoupling Mechanism and PIMs. If approved, the overall net retail revenue increase would be $727 million in Year 1 and $275 million in Year 2, for a combined total of $1 billion or 15.0%. The application also requests an ROE of 10.95% with an equity ratio of 53%. The rate increase is driven primarily by major transmission and distribution investments since the last rate case and projected in the MYRP, as well as investments in energy storage and solar assets. Duke Energy Carolinas has requested the total Year 1 rates to be effective no later than January 1, 2027. The evidentiary hearing is scheduled to commence on July 7, 2026. 2024 South Carolina Rate Case In January 2024, Duke Energy Carolinas filed a rate case with the PSCSC to request an increase in base rate retail revenues. In May 2024, Duke Energy Carolinas and the South Carolina Office of Regulatory Staff, as well as other consumer, environmental, and industrial intervening parties, filed a settlement reso lving all issues in the base rate proceeding. The major components of the settlement include a $240 million annual customer rate increase, prior to a reduction from the accelerated return to customers of federal unprotected Property, Plant and Equipment rel ated EDIT of $84 million annually over the first two years. The settlement includes an ROE of 9.94% with an equity ratio of 51.21% and resolved recovery of the continued investments in the grid, the Company's new corporate headquarters and environmental compliance costs. The PSCSC held a hearing in May 2024, to consider evidence supporting the settlement. On July 3, 2024, the PSCSC issued its final order approving an increase in base rates and approving nearly all components of the settlement. The order revised recovery of certain environmental compliance costs, the only provision of the settlement agreement not fully approved by the PSCSC. As a result, Duke Energy Carolinas recognized pretax charges of $33 million within Impairment of assets and other charges, $2 million within Operation, maintenance and other, partially offset by an $11 million reduction in Interest expense, for the year ended Decem ber 31, 2024, on the Consolidated Statements of Operations. Based upon the order, after accelerating the EDIT giveback to customers, the net rate increase is $150 million annually for the first two years. Revised customer rat es were effective August 1, 2024, an d are based upon a South Carolina retail rate base of $7.4 billion. This matter is now fully resolved. 2025 South Carolina Rate Case On July 1, 2025, Duke Energy Carolinas filed a base rate case with the PSCSC requesting an increase in electric base rates. The request for the rate increase was driven by significant capital investments, including generation plant additions, as well as transmission, distribution and grid improvements. On November 11, 2025, Duke Energy Carolinas filed a comprehensive settlement with the South Carolina Office of Regulatory Staff and other intervenors in the case resolving all revenue requirement issues in the base rate proceeding. The settlement included an annual net increase in electric rates of approximately $19 million including the flow back of PTC benefits to customers, an ROE of 9.99% and an equity ratio of 53%. On December 31, 2025, the PSCSC issued an order approving the settlement agreement without modification. Revised customer rates will become effective on March 1, 2026. Oconee Subsequent License Renewal On June 7, 2021, Duke Energy Carolinas filed a subsequent license renewal (SLR) application for Oconee with the NRC to renew the operating licenses. On March 31, 2025, the NRC issued the subsequent renewed licenses for Oconee, allowing an additional 20 years of operation to 2053 (units 1 and 2) and 2054 (unit 3). Bad Creek License Extension On July 14, 2025, Duke Energy Carolinas filed its final license application with the FERC for the Bad Creek Pumped Storage Hydroelectric Station. The application, if approved, would extend plant operations for an additional 50 years. The curr ent license expires in July 2027 and the renewal would extend the operating license of the facility to 2077. A FERC ruling is expected in 2027. Anderson County Combined Cycle CECPCN On October 30, 2025, Duke Energy Carolinas filed with the PSCSC an application for a C ECPCN to construct and operate a new 1,365-MW natural gas CC generating facility with hydrogen capability in Anderson County, South Carolina. The preliminary estimate of the total project cost is approximately $3.2 billion, inclusive of financing costs. Subject to negotiation of final contractual terms, the new CC will be co-owned with North Carolina Electric Membership Corporation (NCEMC) and Central Electric Power Cooperative (CEPC), with Duke Energy Carolinas owning approximately 1,170 MW, NCEMC owning 100 MW and CEPC owning the remaining 95 MW. If approved, construction is anticipated to begin in 2027 and the facility would be expected to be in service by the end of 2030. An evidentiary hearing with the PS CSC occurred on February 25, 2026, and a final order is expected to be issued no later than April 28, 2026. Buck Combustion Turbines CPCN On November 21, 2025, Duke Energy Carolinas filed with the NCUC an application to construct and operate two hydrogen-capable advanced-class simple-cycle CTs at the site of the existing Buck CC Station. The two new CTs, totaling approximately 850 MW, will provide incremental peaking generation to serve Duke Energy Carolinas' customers growing energy needs. Pending regulatory approvals, construction of the CTs is planned to start in 2027 with the units targeted to be placed in service by the end of 2029. As part of the application, Duke Energy Carolinas noted that the recovery of CWIP during the construction period for the proposed facility will not be included in rate base and will instead accrue AFUDC. The 2030 North Carolina retail revenue requirement for the proposed facility is estimated to be $154 million, representing an approximate average North Carolina retail rate increase of 2.3% across all classes. Marshall Combustion Turbines CPCN In March 2024, Duke Energy Carolinas filed with the NCUC an application to construct and operate two hydrogen-capable advanced-class simple-cycle CTs at the site of the existing Marshall Steam Station. The two new CTs, totaling approximately 850 MW, will enable the retirement of Marshall coal units 1 and 2 and provide incremental capacity to support system capacity needs and expanded flexibility to support integration of renewables. Pending regulatory approvals, the CTs are targeted to be placed in service by the end of 2028. In December 2024, the NCUC issued its order granting the CPCN authorizing construction and the NCDEQ issued final air permits for the two CTs. Certain preliminary construction activities are ongoing and on December 1, 2025, Duke Energy Carolinas filed an application requesting the NCUC's ongoing review of the construction of the two CTs that are planned to operate at the Marshall Steam Station. The application requests that the NCUC find that Duke Energy Carolinas’ construction costs incurred for the CTs during the prior 12-month reporting period are prudent and reasonable. These activities include actions related to site preparation and the ordering of certain long-lead-time equipment. The application also requests that the NCUC modify the existing CPCN for the CTs to reflect a revision to the cost estimate for the units. A decision on the application is anticipated by the third quarter of 2026. On January 30, 2026, Duke Energy Carolinas filed an application for an out-of-state certificate with the PSCSC requesting that it find that the North Carolina-sited facility comprised of two new advanced class CTs at the existing Marshall Steam station is in the public convenience and necessity for South Carolina retail customers. The PSCSC is expected to make a decision on the application by the end of July 2026. Duke Energy Progress Regulatory Assets and Liabilities The following tables present the regulatory assets and liabilities recorded on Duke Energy Progress' Consolidated Balance Sheets.
| December 31, |  | Earns/Pays | Recovery/Refund
(in millions) | 2025 | 2024 |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
AROs – coal ash | $ | 1,531 |  | $ | 1,322 |  |  | Yes | (b)
AROs – nuclear and other | 554 |  | 900 |  |  |  | (c)
Storm cost securitized balance, net | 1,239 |  | 822 |  |  |  | 2046
Accrued pension and OPEB(d) | 396 |  | 439 |  |  | Yes | (i)
Deferred fuel and purchased power | 227 |  | 277 |  |  | (e) | 2028
Storm cost deferrals | 20 |  | 276 |  |  | Yes | (b)
DSM/EE(d) | 229 |  | 188 |  |  | Yes | (g)
NCEMPA deferrals(d) | 202 |  | 179 |  |  | (f) | 2042
Retired generation facilities(d) | 87 |  | 108 |  |  | Yes | (b)
Incremental COVID-19 expenses(d) | 94 |  | 89 |  |  |  | (b)
Hedge costs deferrals | 87 |  | 85 |  |  |  | (b)
AMI(d) | 39 |  | 54 |  |  | Yes | (b)
Grid deferral(d) | 63 |  | 54 |  |  | Yes | (b)
Nuclear deferral | 53 |  | 53 |  |  |  | 2027
Customer connect project(d) | 42 |  | 45 |  |  | Yes | (b)
Vacation accrual | 45 |  | 43 |  |  |  | 2026
PISCC and deferred operating expenses | 37 |  | 37 |  |  | Yes | 2054
Decoupling | 27 |  | 32 |  |  | Yes | (b)
COR settlement | 28 |  | 29 |  |  | Yes | (b)
Deferred coal ash handling system costs(d) | 13 |  | 17 |  |  | Yes | (b)
Deferred asset – Harris COLA | 4 |  | 10 |  |  |  | (b)
Other | 178 |  | 122 |  |  |  | (b)
Total regulatory assets | 5,195 |  | 5,181 |  |  |  |
Less: Current portion | 652 |  | 626 |  |  |  |
Total noncurrent regulatory assets | $ | 4,543 |  | $ | 4,555 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
COR regulatory liability(d) | $ | 3,084 |  | 2,984 |  |  |  | (h)
Net regulatory liability related to income taxes(j) | 1,206 |  | $ | 1,318 |  |  | Yes | (b)
Hedge cost deferrals | 126 |  | 151 |  |  |  | (b)
Renewable energy credits | 146 |  | 139 |  |  | Yes | (b)
Storm cost recovery | 90 |  | 6 |  |  | Yes | (b)
Deferred nuclear PTC | 197 |  | 95 |  |  | Yes | (b)
Accrued pension and OPEB(d) | 11 |  | 12 |  |  | Yes | (i)
Deferred fuel and purchased power | 10 |  | 10 |  |  | (e) | 2028
Other | 211 |  | 203 |  |  |  | (b)
Total regulatory liabilities | 5,081 |  | 4,918 |  |  |  |
Less: Current portion | 274 |  | 348 |  |  |  |
Total noncurrent regulatory liabilities | $ | 4,807 |  | $ | 4,570 |  |  |  |
(a) Regulatory assets and liabilities are excluded from rate base unless otherwise noted. (b) The expected recovery or refund period varies or has not been determined. (c) Recovery period for costs related to nuclear facilities runs through the decommissioning period of each unit. (d) Included in rate base. (e) Pays interest on over-recovered costs in North Carolina. Includes certain purchased power costs in North Carolina and South Carolina and costs of distributed energy in South Carolina. The asset balance principally relates to North Carolina costs while the liability balance relates to South Carolina. (f) South Carolina retail allocated costs are earning a return. (g) Includes incentives on DSM/EE investments and is recovered through an annual rider mechanism. (h) Recovered over the life of the associated assets. (i) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail. (j) Includes regulatory liabilities related to the change in the federal tax rate as a result of the Tax Act and the change in the North Carolina tax rate. Portions are included in rate base. 2022 North Carolina Rate Case In October 2022, Duke Energy Progress filed a PBR application with the NCUC to request an increase in base rate retail revenues. The rate request before the NCUC included an MYRP to recover projected capital investments during the three-year MYRP period. In addition to the MYRP, the PBR application included an Earnings Sharing Mechanism, Residential Decoupling Mechanism and PIMs as required by HB951. In April 2023, Duke Energy Progress filed with the NCUC a partial settlement with the North Carolina Public Staff, which included agreement on many aspects of Duke Energy Progress' three-year MYRP proposal. In May 2023, CIGFUR II joined this partial settlement and the North Carolina Public Staff and CIGFUR II filed a separate settlement reaching agreement on PIMs, Tracking Metrics and the Residential Decoupling Mechanism under t he PBR application. On August 18, 2023, the NCUC issued an order approving Duke Energy Progress' PBR application, as modified by the partial settlements and the order, including an overall retail revenue increase of $233 million in Year 1, $126 million in Year 2 and $135 million in Year 3, for a combined total of $494 million. Key aspects of the order include the approval of North Carolina retail rate base for the historic base case of approximately $12.2 billion and capital projects and related costs to be included in the three-year MYRP, including $3.5 billion (North Carolina retail allocation) projected to go in service over the MYRP period. The order established an ROE of 9.8% based upon an equity ratio of 53% equity and approved, with certain adjustments, depreciation rates and the recovery of grid improvement plan costs and certain deferred COV ID-related costs. Additionally, the Residential Decoupling Mechanism and PIMs were approved as requested under the PBR application and revised by the partial settlements. As a result of the order, Duke Energy Progress recognized pretax charges of $28 million within Impairment of assets and other charges, which primarily related to certain COVID-19 deferred costs, and $8 million within Operation, maintenance and other, for the year ended December 31, 2023, on the Consolidated Statements of Operations. Duke Energy Progress implemented interim rates on June 1, 2023, and implemented revised Year 1 rates and the residential decoupling on October 1, 2023. In October 2023, CIGFUR II and Haywood Electric Membership Corporation each filed a Notice of Appeal of the August 18, 2023 NCUC order. Both parties appealed certain matters that do not impact the overall revenue requirement in the rate case. Specifically, they appealed the interclass subsidy reduction percentage, and CIGFUR II also appealed the Customer Assistance Program and the equal percentage fuel cost allocation methodology. In November 2023, the AGO filed a Notice of Cross Appeal of the NCUC’s determination regarding the exclusion of electric vehicle revenue from the residential decoupling mechanism. In November 2023, Duke Energy Progress, the North Carolina Public Staff, CIGFUR II, and a number of other parties reached a settlement pursuant to which CIGFUR II agreed not to pursue its appeal of the Customer Assistance Program. In July 2024, the Supreme Court of North Carolina consolidated these appeals with the parallel appeals of the NCUC's order regarding the Duke Energy Carolinas PBR application. Briefing is compl ete and oral arguments occurred in February 2025. Duke Energy Progress anticipates a decision to be issued in the first half of 2026. 2025 North Carolina Rate Case On November 20, 2025, Duke Energy Progress filed a PBR application with the NCUC to request an increase in base rate retail revenues. The PBR Application includes an MYRP to recover projected capital investments during a two-year MYRP period. In addition to the MYRP, the PBR Application includes an Earnings Sharing Mechanism, Residential Decoupling Mechanism and PIMs. If approved, the overall net retail revenue increase would be $529 million in Year 1 and $200 million in Year 2, for a combined total of $729 million or 15.1%, which includes the flow back of PTC benefits to customers through a proposed PTC rider similar to Duke Energy Carolinas. The application also requests an ROE of 10.95% with an equity ratio of 53%. The rate increase is driven primarily by major transmission and distribution investments since the last rate case and projected in the MYRP, as well as investments in energy storage and solar assets. Duke Energy Progress has requested the total Year 1 rates to be effective no later than January 1, 2027. The evidentiary hearing is scheduled to commence on August 11, 2026. 2025 South Carolina Rate Case On June 12, 2025, Duke Energy Progress filed a base rate case with the PSCSC requesting an increase in electric base rates. The request for the rate increase was driven by significant capital investments, primarily including transmission, distribution and grid improvements. On October 27, 2025, Duke Energy Progress filed a comprehensive settlement with the South Carolina Office of Regulatory Staff and other intervenors in the case resolving all revenue requirement issues in the base rate proceeding. The settlement included an annual net increase in elect ric rates of approximately $40 million including the flow back of PTC benefits to customers, an ROE of 9.99% and an equity ratio of 53% and was subject to review and approval by the PSCSC. On December 12, 2025, the PSCSC issued an order approving the settlement agreement without modificati on. Revised customer rates were implemented on February 1, 2026. Person County Combined Cycle CPCNs On February 7, 2025, Duke Energy Progress filed with the NCUC its application to construct and operate a second 1,360-MW hydrogen-capable, advanced-class CC unit in Person County at the Roxboro Plant. NCEMC has also notified Duke Energy Progress of NCEMC's intent to co-own approximately 225 MW of the second CC and Duke Energy Progress and NCEMC began negotiations on the contractual arrangement in the second quarter of 2025. NCEMC has the right to co-own the facility under its existing supply agreement with Duke Energy Progress. Pending regulatory approvals, construction of the second CC is planned to start in 2026 with the unit targeted to be placed in service by the end of 2029. As part of the application, Duke Energy Progress noted that the recovery of CWIP during the construction period for the proposed facility may be pursued in the future. The 2030 North Carolina retail revenue requirement for the proposed second unit is estimated to be $113 million, representing an approximate average retail rate increase of 2.6% across all classes. The air permit was issued by the NCDEQ in December 2024. On October 16, 2025, the NCUC issued its order granting the CPCN. Certain preliminary construction activities are ongoing at both Person County CC units. On January 30, 2026, Duke Energy Progress filed an application for out-of-state certificates with the PSCSC requesting that it find that the two new CC units, totaling approximately 2,720 MW, sited at the Person County facilities in North Carolina are in the public convenience and necessity for South Carolina retail customers. The PSCSC is expected to make a decision on the application by the end of July 2026. Robinson Subsequent License Renewal In April 2025, Duke Energy Progress filed an SLR application for Robinson with the NRC to renew Robinson’s operating license for an additional 20 years. The current license expires in 2030 and the renewal would extend the operating license of the facility to 2050. The NRC is performing the safety and environmental reviews for the application and is working through 2025 government shutdown impacts in an effort to maintain the schedule for a decision by April 2026. Duke Energy Florida Regulatory Assets and Liabilities The following tables present the regulatory assets and liabilities recorded on Duke Energy Florida's Consolidated Balance Sheets.
| December 31, |  | Earns/Pays | Recovery/Refund
(in millions) | 2025 | 2024 |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
Storm cost deferrals | $ | 29 |  | 962 |  |  | (e) | (b)
Nuclear asset securitized balance, net | 717 |  | 771 |  |  |  | 2036
COR regulatory asset | 746 |  | 571 |  |  | Yes | (b)
Accrued pension and OPEB(c) | 348 |  | 389 |  |  | Yes | (f)
Retired generation facilities(c) | 89 |  | 94 |  |  | Yes | 2044
Customer connect project(c) | 65 |  | 71 |  |  | Yes | 2037
Qualifying facility contract buyouts(c) | 55 |  | 62 |  |  | Yes | 2034
Hedge costs deferrals(c) | 48 |  | 41 |  |  | Yes | (b)
AMI(c) | 9 |  | 16 |  |  | Yes | 2032
AROs – coal ash | 13 |  | 13 |  |  |  | (b)
AROs – nuclear and other | 10 |  | 5 |  |  |  | (b)
Other | 79 |  | 91 |  |  | (d) | (b)
Total regulatory assets | 2,208 |  | 3,086 |  |  |  |
Less: Current portion | 102 |  | 1,022 |  |  |  |
Total noncurrent regulatory assets | $ | 2,106 |  | $ | 2,064 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
Net regulatory liability related to income taxes(c) | $ | 535 |  | $ | 564 |  |  |  | (b)
Hedge cost deferrals(c) | 122 |  | 130 |  |  | Yes | (b)
Deferred fuel and purchased power | 18 |  | 84 |  |  | (e) | 2026
Storm reserve(c) | 132 |  | — |  |  | Yes | (b)
Other | 63 |  | 84 |  |  | (d) | (b)
Total regulatory liabilities | 870 |  | 862 |  |  |  |
Less: Current portion | 76 |  | 174 |  |  |  |
Total noncurrent regulatory liabilities | $ | 794 |  | $ | 688 |  |  |  |
(a) Regulatory assets and liabilities are excluded from rate base unless otherwise noted. (b) The expected recovery or refund period varies or has not been determined. (c) Included in rate base. (d) Certain costs earn/pay a return. (e) Earns commercial paper rate. (f) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail. Clean Energy Connection In July 2020, Duke Energy Florida petitioned the FPSC for approval of a voluntary solar program consisting of 10 new solar generating facilities with combined capacity of 749 MW. The FPSC approved the program in January 2021, allowing participants to support cost-effective solar development in Florida by paying a subscription fee based on per kilowatt subscriptions and receiving a credit on their bill based on the actual generation associated with their portion of the solar portfolio. The 10 new solar generation facilities were completed and all of the remaining sites were in service by the end of 2024 at a cost of approximately $1.1 billion. These investments are included in base rates, offset by the revenue from the subscription fees, with credits included in the fuel cost recovery clause. In February 2021, the League of United Latin American Citizens (LULAC) filed a notice of appeal of the FPSC’s order approving the Clean Energy Connection to the Supreme Court of Florida. On May 27, 2022, the Supreme Court of Florida issued an order remanding the case back to the FPSC so that the FPSC can amend its order to better address some of the arguments raised by LULAC. In September 2022, the FPSC issued a revised order and submitted it to the Supreme Court of Florida. On July 17, 2025, the Supreme Court of Florida issued an order affirming the revised FPSC order. The ruling did not change the solar program or have other financial implications. This matter is now fully resolved. Storm Protection Plan At least every three years, Duke Energy Florida must file an SPP with the FPSC. Each plan covers a 10-year period and includes investments in transmission and distribution meant to strengthen infrastructure, reduce outage times associated with extreme weather events, reduce restoration costs and improve overall service reliability. In January 2025, Duke Energy Florida filed an SPP for approval with the FPSC for the 2026-2035 time frame reflecting approximately $7 billion of capital investment in transmission and distribution. On May 16, 2025, Duke Energy Florida and the OPC filed joint stipulations to resolve all matters, and the FPSC issued an order on June 19, 2025, approving those stipulations. The stipulations require Duke Energy Florida to defer certain work in two programs from 2026 to 2027 and later. The remainder of Duke Energy Florida's filed SPP was approved without modification. This matter is now fully resolved. 2024 Florida Rate Case In April 2024, Duke Energy Florida filed a formal request for new base rates with the FPSC. Duke Energy Florida proposed a three-year rate plan that would begin in January 2025, once its current base rate settlement agreement concludes at the end of 2024. Duke Energy Florida proposed multiyear rate increases that use the projected 12-month periods ending December 31, 2025, 2026, and 2027 as the test years, with adjusted rates to be effective with the first billing period of January 2025, 2026, and 2027, respectively. In July 2024, Duke Energy Florida filed a settlement agreement with the FPSC. The parties to the settlement include Duke Energy Florida, the Office of Public Counsel and other intervening parties. Pursuant to the settlement, the parties agreed to a base rate stay-out provision that expires year-end 2027; however, Duke Energy Florida is allowed an increase to its base rates in 2025 and 2026, as well as utilization of certain tax benefits in lieu of a revenue increase in 2027. Additionally, revenue increases related to solar investments will be recovered via the Solar Base Rate Adjustment mechanism. The parties also agreed to an ROE band of 9.3% to 11.3% with a midpoint of 10.3% and an equity ratio of 53%. The agreement provides for $203 million and $59 million in base rate increases in 2025 and 2026, respectively, as well as increases associated with investments in 12 new solar facilities as they come on line. In August 2024, the FPSC approved the settlement agreement without modification and a final order was issued on November 12, 2024. New rates were effective January 1, 2025. This matter is now fully resolved. Hurricanes Debby, Helene and Milton In 2024, Hurricane Debby (Category 1 storm), Hurricane Helene (Category 4 storm) and Hurricane Milton (Category 3 storm) made landfall in Florida and caused significant damage. Duke Energy Florida has certain existing storm reserve regulatory liability amounts, which are applied to the recovery of storm costs. The storm reserve amount was approximately $63 million as of July 31, 2024, prior to the damage resulting from hurricanes Debby, Helene and Milton. Duke Energy Florida is permitted to petition the FPSC for recovery of incremental operation and maintenance costs resulting from the storms and to replenish the retail customer storm reserve to approximately $132 million. In December 2024, Duke Energy Florida filed its petition to recover the estimated costs incurred to respond to all three storms, including replenishment of the storm reserve, seeking recovery of approximately $1.1 billion, over 12 months beginning with the first billing cycle in March 2025. On February 4, 2025, the FPSC voted to approve Duke Energy Florida's request for recovery of these estimated storm costs as filed, subject to true-up after the actual costs are filed. New rates were effective March 1, 2025. Approximately $4 million and $936 million of the operation and maintenance expenses, net of storm reserves, are deferred in Regulatory assets within Current assets as of December 31, 2025, and December 31, 2024, respectively. Approximately $75 million of capital related to these storms will be sought for recovery in future base rate case filings. On January 5, 2026, Duke Energy Florida filed a notice with the FPSC to stop recovery of the storm cost charge because the costs were fully recovered and the storm reserve was fully replenished earlier than anticipated, primarily due to lower actual incurred storm costs as compared to preliminary estimates. The notice was administratively approved and revised rates with the storm charge removed were effective with the first billing cycle in February 2026. Duke Energy Ohio Regulatory Assets and Liabilities The following tables present the regulatory assets and liabilities recorded on Duke Energy Ohio's Consolidated Balance Sheets.
| December 31, |  | Earns/Pays | Recovery/Refund
(in millions) | 2025 | 2024 |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
CEP deferral | $ | 200 |  | 195 |  |  | Yes | (b)
Accrued pension and OPEB | 121 |  | 131 |  |  |  | (d)
COR regulatory asset | 114 |  | 75 |  |  |  | (b)
Customer connect project | 39 |  | 44 |  |  |  | (b)
Network Integration Transmission Services deferral | 31 |  | 31 |  |  | Yes | (b)
Transmission expansion obligation | 30 |  | 31 |  |  |  | (b)
Decoupling | 18 |  | 29 |  |  |  | (b)
Deferred pipeline integrity costs | 26 |  | 28 |  |  | Yes | (b)
East Bend deferrals(c) | 20 |  | 24 |  |  | Yes | (b)
Propane caverns | 22 |  | 24 |  |  |  | (b)
PISCC and deferred operating expenses(c) | 14 |  | 15 |  |  | Yes | 2083
AROs – coal ash | 14 |  | 14 |  |  | Yes | (b)
Deferred fuel and purchased power | 25 |  | 8 |  |  |  | 2026
Other | 98 |  | 144 |  |  |  | (b)
Total regulatory assets | 772 |  | 793 |  |  |  |
Less: Current portion | 86 |  | 88 |  |  |  |
Total noncurrent regulatory assets | $ | 686 |  | $ | 705 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
Net regulatory liability related to income taxes | $ | 405 |  | $ | 432 |  |  |  | (b)
Accrued pension and OPEB | 13 |  | 14 |  |  |  | (d)
Other | 109 |  | 53 |  |  |  | (b)
Total regulatory liabilities | 527 |  | 499 |  |  |  |
Less: Current portion | 57 |  | 34 |  |  |  |
Total noncurrent regulatory liabilities | $ | 470 |  | $ | 465 |  |  |  |
(a) Regulatory assets and liabilities are excluded from rate base unless otherwise noted. (b) The expected recovery or refund period varies or has not been determined. (c) Included in rate base. (d) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail. Duke Energy Ohio 2022 Natural Gas Base Rate Case In June 2022, Duke Energy Ohio filed a natural gas base rate case application with the PU CO. The drivers for this case were capital invested since Duke Energy Ohio's last natural gas base rate case in 2012. Duke Energy Ohio also sought to adjust the caps on its CEP Rider. In April 2023, Duke Energy Ohio filed a stipulation with all parties to the case except the Ohio Consumers' Counsel (OCC). In the stipulation, the parties agreed to approximately $32 million in revenue increases with an equity ratio of 52.32% and an ROE of 9.6%, and adjustments to the CEP Rider caps. The stipulation was opposed by the OCC at an evidentiary hearing that concluded in May 2023. On November 1, 2023, PUCO issued an order approving the stipulation as filed and new rates went into effect November 1, 2023. In December 2023, the OCC filed an application for rehearing and the PUCO granted OCC's application for rehearing for further consideration of issues raised. As a result of a Supreme Court of Ohio decision regarding procedural issues related to applications for rehearing, PUCO denied OCC’s rehearing request. In October 2024, the OCC filed its Notice of Appeal with the Supreme Court of Ohio. The case is fully briefed and oral argument occurred October 7, 2025. The matter is now submitted for decision. Duke Energy Ohio 2024 Electric Security Plan In April 2024, Duke Energy Ohio filed with the PUCO a request for an Electric Security Plan (ESP). The ESP application proposed a three-year term from June 1, 2025, through May 31, 2028, and included continuation of market-based rates for generation supply through competitive procurement processes and continuation and expansion of existing rider mechanisms. Duke Energy Ohio proposed a new rider mechanism relating to electric distribution infrastructure modernization programs, which may be enabled by and partially funded through federal or state funding opportunities, as well as future battery storage projects, and two electric vehicle programs. Additional proposals included new rider mechanisms related to solar for all investments for low-income and disadvantaged communities, low-income senior citizen bill assistance, and EE and demand-side management programs. In November 2024, Duke Energy Ohio filed a stipulation that the majority of the intervenors signed as either signatory or non-opposing parties. The stipulation includes the continuation of market-based rates for generation supply through competitive procurement auctions and the continuation of all existing riders. It further establishes new caps for certain riders. Duke Energy Ohio also agreed to withdraw its proposals for an infrastructure modernization rider, battery storage projects and electric vehicle programs. The stipulation included a residential EE program with provisions for low-income customers. On May 14, 2025, PUCO issued its order, approving the stipulation without modification. On May 15, 2025, the governor of Ohio signed Ohio Substitute House Bill 15 (HB15) into law with an effective date of August 14, 2025. HB15 requires electric distribution utilities to file a base rate case every three years, commencing no later than December 31, 2029, and established an opportunity to apply for approval of a three-year rate plan with forward-looking test periods to mitigate regulatory lag. HB15 eliminates ESPs and certain distribution-related riders, but allows ESPs approved as of its effective date to remain in place through the end of their authorized term. HB15 also eliminated Duke Energy Ohio's Legacy Generation Rider upon the effective date of HB15 and prevents the PUCO from future reauthorization of similar arrangements. As a result of HB15, future losses related to Duke Energy Ohio's Inter-Company Power Agreement with OVEC will not be recoverable from retail customers. Duke Energy Ohio RTO Adder On February 24, 2022, the OCC filed a complaint asserting that FERC should reduce the ROE utilized in transmission formulas for Duke Energy Ohio and certain transmission providers by eliminating the 50 basis point adder associated with RTO membership. The OCC contends this is required because Ohio law mandates that transmission owning utilities join an RTO and that the 50 basis point adder is only applicable where RTO membership is voluntary. On December 15, 2022, FERC denied the complaint as it related to Duke Energy Ohio, but granted it for certain other transmission providers. As a result of appeal by certain other transmission providers, the U.S. Court of Appeals for the Sixth Circuit (Sixth Circuit) on January 17, 2025, reversed the prior decision from FERC. In the decision, the Sixth Circuit ruled the 50 basis point adder is available only where RTO membership is voluntary. The decision noted that Ohio law requires Ohio's transmission utilities to be a member of an RTO and therefore it is unlawful for FERC to remove the adder from certain transmission providers but not also remove the adder from Duke Energy Ohio. As a result, the issue was remanded back to FERC to revise their prior decision. As a result of the ruling, Duke Energy Ohio recognized a pretax charge during 2025, the results of which were not material. On March 26, 2025, the Sixth Circuit denied requests for rehearing. On April 16, 2025, the Sixth Circuit agreed to stay the mandate pending further appeal to the U.S. Supreme Court. On July 17, 2025, Duke Energy Ohio filed a respondent brief at the U.S. Supreme Court requesting review of the Sixth Circuit's decision. On November 10, 2025, the U.S. Supreme Court denied the appeal, and on November 13, 2025, the Sixth Circuit remanded the case back to FERC. An order from the FERC is expected in the first quarter of 2026. Duke Energy Kentucky 2022 Electric Base Rate Case In December 2022, Duke Energy Kentucky filed a base rate case with the KPSC driven by capital investments to strengthen the electricity generation and delivery systems along with adjusted depreciation rates for the East Bend and Woodsdale CT generation stations. Duke Energy Kentucky also requested approval for new programs and tariff updates, including a voluntary community-based renewable subscription program and two electric vehicle charging programs. The KPSC issued an order on October 12, 2023, including a $48 million increase in base revenues, an ROE of 9.75% for electric base rates and 9.65% for electric riders and an equity ratio of 52.145%. New rates went into effect October 13, 2023. Duke Energy Kentucky's request to adjust the depreciation rates of East Bend was denied and the KPSC ordered depreciation rates with a 2041 retirement date for the unit. The KPSC approved the request to align depreciation rates of Woodsdale CT with a 2040 retirement date and denied the voluntary community-based renewable subscription program and electric vehicle charging programs. Revised rates were implemented in August 2024 after a rehearing request. On December 14, 2023, Duke Energy Kentucky filed an appeal with the Franklin County Circuit Court on certain matters for which the KPSC denied rehearing, specifically as it relates to the inclusion of decommissioning costs in depreciation rates for East Bend and Woodsdale. The case is fully briefed and Duke Energy Kentucky is awaiting the scheduling of oral arguments and the outcome of the appeal. Duke Energy Kentucky 2024 Electric Base Rate Case In December 2024, Duke Energy Kentucky filed a base rate case with the KPSC requesting an annualized increase in electric base rates of approximately $70 million. The request for the rate increase was driven by capital investments to strengthen the electricity generation and delivery systems. New rates went into effect on July 3, 2025, subject to refund. On October 2, 2025, the KPSC issued its decision approving a $44 million revenue requirement increase, with an ROE of 9.8% and an equity ratio of 52.73%. The KPSC further directed Duke Energy Kentucky to issue refunds of amounts collected since July 3, 2025, that exceed what has been approved by the order within 60 days. On October 22, 2025, Duke Energy Kentucky filed a petition for rehearing with the KPSC related to the treatment of terminal net salvage, rate case expense and recovery of costs from PJM. Additionally, on October 22, 2025, one commercial customer filed a petition for rehearing with the KPSC on a rate design issue, which does not impact the overall revenue requirement. On November 10, 2025, Duke Energy Kentucky’s motions for reconsideration regarding rate case expense and recovery of costs from PJM were granted and the motion for reconsideration regarding the treatment of terminal net salvage was denied by the KPSC. In December 2025, $7 million was refunded to customers. Duke Energy Kentucky 2025 Natural Gas Base Rate Case On June 2, 2025, Duke Energy Kentucky filed a base rate case with the KPSC requesting an increase in natural gas base rates. The request for the rate increase was driven by capital investments to strengthen the natural gas delivery system. On October 20, 2025, Duke Energy Kentucky filed a settlement with the Office of the Kentucky Attorney General, that if approved, would resolve all issues in the case. The settlement included an increase in natural gas base rates of approximately $22 million, an ROE of 9.8% for base rates (9.7% for riders), an equity ratio of 52.649%, and approval for cost recovery of Aldyl-A pipe a nd service replacements through an existing rider. On December 23, 2025, the KPSC approved the settlement without modification. New rates went into effect January 3, 2026. This matter is now fully resolved. Duke Energy Indiana Regulatory Assets and Liabilities The following tables present the regulatory assets and liabilities recorded on Duke Energy Indiana's Consolidated Balance Sheets.
| December 31, |  | Earns/Pays | Recovery/Refund
(in millions) | 2025 | 2024 |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
AROs – coal ash | $ | 606 |  | $ | 554 |  |  | Yes | (b)
PISCC and deferred operating expenses(c) | 201 |  | 237 |  |  | Yes | (b)
Accrued pension and OPEB | 203 |  | 212 |  |  |  | (e)
Retired generation facilities(c) | 20 |  | 25 |  |  | Yes | 2030
Hedge costs deferrals | 30 |  | 23 |  |  |  | (b)
Customer connect project | 18 |  | 19 |  |  |  | (b)
Deferred fuel and purchased power | 60 |  | — |  |  |  | 2026
Storm cost deferrals | 21 |  | 17 |  |  |  | (b)
AMI | 10 |  | 12 |  |  |  | 2031
Other | 56 |  | 54 |  |  |  | (b)
Total regulatory assets | 1,225 |  | 1,153 |  |  |  |
Less: Current portion | 193 |  | 113 |  |  |  |
Total noncurrent regulatory assets | $ | 1,032 |  | $ | 1,040 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
Net regulatory liability related to income taxes | $ | 641 |  | $ | 725 |  |  |  | (b)
COR regulatory liability(c) | 444 |  | 434 |  |  |  | (d)
Accrued pension and OPEB | 113 |  | 139 |  |  |  | (e)
Hedge cost deferrals | 106 |  | 103 |  |  |  | (b)
Deferred fuel and purchased power | — |  | 21 |  |  |  |
DSM / EE | 19 |  | 11 |  |  |  | (b)
Other | 137 |  | 154 |  |  |  | (b)
Total regulatory liabilities | 1,460 |  | 1,587 |  |  |  |
Less: Current portion | 275 |  | 183 |  |  |  |
Total noncurrent regulatory liabilities | $ | 1,185 |  | $ | 1,404 |  |  |  |
(a) Regulatory assets and liabilities are excluded from rate base unless otherwise noted. (b) The expected recovery or refund period varies or has not been determined. (c) Included in rate base. (d) Refunded over the life of the associated assets. (e) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail. Indiana Coal Ash Recovery In Duke Energy Indiana’s 2019 rate case, the IURC opened a subdocket for post-2018 coal ash related expenditures. In April 2020, Duke Energy Indiana filed testimony in the coal ash subdocket requesting recovery for post-2018 coal ash basin closure costs associated with closure plans that were approved by the Indiana Department of Environmental Management (IDEM) at that time as well as continued deferral approval and carrying costs on the balance of such coal ash basin closure costs. On November 3, 2021, the IURC issued an order allowing recovery of the post-2018 coal ash basin closure costs, as well as continuing deferral, with carrying costs on the balance. The OUCC and the Duke Industrial Group appealed. The Indiana Court of Appeals issued its opinion on February 21, 2023, reversing the IURC's order to the extent that it allowed Duke Energy Indiana to recover federally mandated costs incurred prior to the IURC's November 3, 2021 order. In addition, the court found that any costs incurred pre-petition to determine federally mandated compliance options were not specifically authorized by the statute and should also be disallowed. In 2023, Duke Energy Indiana filed its proposal to remove from rates certain costs incurred prior to the IURC's November 3, 2021 order date. On September 20, 2023, the IURC approved Duke Energy Indiana's proposal to remove the costs from its rates and assessed simple interest on the refunds at a rate of 4.71%, beginning from when the costs were initially recovered from customers. I n the 2024 Indiana Rate Case, Duke Energy Indiana included a request to recover the pre-order costs denied by the Indiana Court of Appeals and certain future coal ash closure costs as part of depreciation costs. The IURC's January 29, 2025 order in the 2024 Indiana Rate Case denied recovery of the pre-order costs previously denied by the Indiana Court of Appeals but approved the recovery of certain future coal ash closure costs as part of depreciation costs. In 2023, Duke Energy Indiana filed a petition under the amended version of the federal mandate statute for additional post-2018 coal ash closure costs for the remaining basins not included in the Indiana coal ash recovery case from 2020. On May 8, 2024, the IURC issued a CPCN and approved these coal ash related compliance projects as federally mandated compliance projects. In June 2024, the Citizens Action Coalition of Indiana (CAC) filed a notice of appeal of the IURC's order. On August 26, 2025, the Indiana Court of Appeals reversed the decision by the IURC concluding that the IURC incorrectly allowed Duke Energy Indiana to collect those coal ash costs from customers. In October 2025, Duke Energy Indiana and the Indiana Office of Attorney General filed separate petitions requesting the Indiana Supreme Court to review the case. On January 26, 2026, the Indiana Supreme Court denied Duke Energy Indiana's and the Indiana Office of Attorney General's petitions. There were no material impacts on the results of operations, cash flows or financial position as a result of this ruling. Duke Energy Indiana is evaluating next steps as it relates to the Indiana Supreme Court's decision. TDSIC 2.0 In November 2021, Duke Energy Indiana filed for approval of the Transmission, Distribution, Storage Improvement Charge 2.0 investment plan for 2023-2028 (TDSIC 2.0). On June 15, 2022, the IURC approved, without modification, TDSIC 2.0, which includes approximately $2 billion in transmission and distribution investments selected to improve customer reliability, harden and improve resiliency of the grid, enable expansion of renewable and distributed energy projects and encourage economic development. In July 2022, the OUCC filed a notice of appeal to the Indiana Court of Appeals in Duke Energy Indiana’s TDSIC 2.0 proceeding. The Indiana Court of Appeals issued its opinion on March 9, 2023, affirming the IURC’s order in its entirety. The Duke Industrial Group filed a petition to transfer to the Indiana Supreme Court. On December 19, 2024, the Indiana Supreme Court affirmed the Indiana Court of Appeals decision, concluding there was substantial evidence that the IURC's conclusion was reasonable and the TDSIC 2.0 plan met the statutory requirements. On January 21, 2025, the Duke Industrial Group filed a motion for rehearing. On March 4, 2025, the Indiana Supreme Court denied the Duke Industrial Group's petition for rehearing. There can be no further appeals on TDSIC 2.0 and this matter is now fully resolved. 2024 Indiana Rate Case In April 2024, Duke Energy Indiana filed an application with the IURC for a rate increase for retail customers. The request for rate increase was driven by $1.6 billion in investments made since the last general rate case filed in 2019 in order to reliably serve customers, improve resiliency of the system, and advance energy solutions. In connection with this rate case, a $29 million increase in a regulatory liability associated with certain employee post-retirement benefits was recorded in December 2024. An order for the rate case was issued by the IURC on January 29, 2025, and revised February 3, 2025, which authorized an ROE of 9.75%, an equity ratio of 53% and an annual revenue increase of $296 million. Based on review of these orders, Duke Energy Indiana identified an inconsistency in the calculation of operating revenues before the effect of trackers. On February 7, 2025, Duke Energy Indiana made a compliance filing in accordance with the IURC's findings in its order and addressed the identified inconsistencies. The compliance filing also clarified the annual revenue increase was approximately $385 million. On February 18, 2025, one industrial customer submitted a filing requesting the IURC to clarify its revenue allocation in these proceedings, which was denied by the Commission on April 16, 2025. On February 25, 2025, the IURC approved Duke Energy Indiana’s compliance filing and new rates were implemented February 27, 2025. The industrial customer filed a notice of appeal on February 28, 2025, regarding cost of service allocation. On April 9, 2025, the IURC issued an order clarifying the intent of its January 29, 2025 order regarding the rate migration adjustment, resulting in revised rates that were effective on May 19, 2025. On May 14, 2025, the industrial customer filed a motion to dismiss its appeal, and on May 20, 2025, the Indiana Court of Appeals granted the industrial customer's motion to dismiss. This matter is now fully resolved. Cayuga Combined Cycle CPCN On February 13, 2025, Duke Energy Indiana filed for a CPCN seeking approval to construct two 1x1 CC natural gas-fired units with a combined winter rating of 1,476 MW. The Cayuga CC Project is proposed to be constructed on the same site as the retiring Cayuga coal-fired steam units with a winter rating of 1,005 MW. The Cayuga CC Project will result in an incremental 471 MW for the Duke Energy Indiana system and will allow Duke Ene rgy Indiana to avoid expected maintenance and environmental compliance costs needed for the coal units to continue operating. The estimated cost of the Cayuga CC project is approximately $3.3 billion, plus actual AFUDC. Du ke Energy Indiana proposed recovery of certain facility costs during construction, including AFUDC, through CWIP ratemaking via a proposed Generation Cost Tracker (GCT). Duke Energy Indiana expects CC 1 to be placed in service in 2029 and CC 2 to be placed in service in 2030. A final air permit was issued by IDEM on March 5, 2025. On June 17, 2025, Duke Energy Indiana entered into a settlement agreement with one of the parties in this proceeding to conduct a study evaluating the feasibility of third-party operation of the Cayuga coal units. On July 11, 2025, Duke Energy Indiana entered into a settlement agreement with an additional party in this proceeding agreeing to the need of the units and addressing accounting and ratemaking components. Neither agreement altered the underlying plans in the pending CPCN application. On October 29, 2025, the IURC issued its order approving the settlement agreements, granting the CPCN and approving cost recovery through the proposed GCT. On November 26, 2025, CAC filed a notice of appeal of the IURC's order. On November 25, 2025, Duke Energy Indiana filed its first GCT tariff for approval to recover Cayuga CC CPCN-related costs, with the proposed factors to take effect in the first April 2026 billing cycle and to remain in place for approximately six months or until superseded by IURC-approved factors in a subsequent filing. The estimated average cumulative retail rate impact during construction and initial in-service periods from April 2026 through May 2031 is approximately 5.6%. Piedmont Regulatory Assets and Liabilities The following tables present the regulatory assets and liabilities recorded on Piedmont's Consolidated Balance Sheets.
| December 31, |  | Earns/Pays | Recovery/Refund
(in millions) | 2025 | 2024 |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
Accrued pension and OPEB(c) | $ | 131 |  | $ | 144 |  |  |  | (g)
Deferred pipeline integrity costs(c) | 91 |  | 101 |  |  |  | 2034
Derivatives – natural gas supply contracts(f) | 72 |  | 94 |  |  |  | 2031
Decoupling | 28 |  | 77 |  |  | Yes | (b)
Pipeline Integrity Management – Transmission/Distribution | 27 |  | 14 |  |  |  | (b)
Deferred purchased gas costs | 26 |  | 9 |  |  | Yes | (b)
AROs – nuclear and other | 25 |  | 25 |  |  |  | (d)
Customer connect project(c) | 22 |  | 24 |  |  |  | 2030
Vacation accrual(c) | 15 |  | 14 |  |  |  | 2026
Other | 19 |  | 26 |  |  | (e) | (b)
Total regulatory assets | 456 |  | 528 |  |  |  |
Less: Current portion | 106 |  | 141 |  |  |  |
Total noncurrent regulatory assets | $ | 350 |  | $ | 387 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
COR regulatory liability(c) | $ | 425 |  | $ | 405 |  |  | (e) | (d)
Net regulatory liability related to income taxes | 353 |  | 366 |  |  |  | (b)
Other | 44 |  | 76 |  |  | (e) | (b)
Total regulatory liabilities | 822 |  | 847 |  |  |  |
Less: Current portion | 20 |  | 64 |  |  |  |
Total noncurrent regulatory liabilities | $ | 802 |  | $ | 783 |  |  |  |
(a) Regulatory assets and liabilities are excluded from rate base unless otherwise noted. (b) The expected recovery or refund period varies or has not been determined. (c) Included in rate base. (d) Recovery over the life of the associated assets. (e) Certain costs earn/pay a return. (f) Balance will fluctuate with changes in the market. (g) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail. 2024 North Carolina Rate Case In April 2024, Piedmont filed an application with the NCUC for a rate increase for retail customers. In September 2024, Piedmont, the Public Staff and other intervening parties filed an Agreement and Stipulation of Settlement with the NCUC resolving all issues in the general rate case. The major components of the settlement include an overall average effective increase in net annual retail revenues of $88 million in the first year and $10 million of additional revenue after the first year. The settlement includes an ROE of 9.8% with an equity ratio of 52.3% and the addition of a rider mechanism for recovery of pipeline integrity management operations and maintenance expenses. The settlement was subject to the review and approval of the NCUC. The evidentiary hearing concluded in September 2024, and Piedmont implemented revised rates November 1, 2024. The NCUC issued its order approving the settlement as filed on January 7, 2025, and this matter is now fully resolved. OTHER REGULATORY MATTERS Potential Coal Plant Retirements The Subsidiary Registrants periodically file IRPs with their state regulatory commissions. The IRPs provide a view of forecasted energy needs over a long term (10 to 20 years) and resources proposed to meet those needs. The IRPs also include planning assumptions around future retirement dates of aging coal-fired generating facilities. Duke Energy Carolinas and Duke Energy Progress received an NCUC order on the 2022 Carbon Plan that concluded th e projected retirement dates for their coal-fired generating facilities were reasonable for planning purposes and further directed that appropriate steps be taken to optimally retire the coal fleet according to such schedule. In August 2023, Duke Energy Carolinas and Duke Energy Progress filed their 2023 systemwide Carolinas Resource Plan with the NCUC and PSCSC, with a supplemental filing in January 2024 that demonstrated a need for additional resources beyond the set of resources identified by the companies in their initial plan. The NCUC and PSCSC issued orders in 2024 generally approving the resource plan. Duke Energy Carolinas and Duke Energy Progress conducted an updated coal retirement analysis for the 2025 Carolinas Resource Plan, consistent with direction by the NCUC in its order approving the 2023 Carolinas Resource Plan and in recognition by both the NCUC and PSCSC of the importance of continuing to assess the orderly retirement of these units. See t he "Other Matters" section of Item 7 Management's Discussion and Analysis for further details on resource plans. Duke Energy continues to evaluate the retirement date assumptions for all coal-fired generating facilities as changes in energy usage and/or growth and availability of repla cement generation could result in different retirement dates of units than their current estimated useful lives. Except as previously discussed related to Duke Energy Kentucky's East Bend plant, rate cases recently filed or approved across all jurisdictions included proposed depreciation rates that approximate earlier retirement dates as outlined in recent IRPs. Duke Energy plans to seek regulatory recovery for amounts that would not be otherwise recovered when any of these assets are retired.

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