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Regulatory Matters | 12 Months Ended
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Dec. 31, 2023
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) | 2023 |  | 2022 |  | 2023 |  | 2022 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Regulatory Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
AROs – coal ash | $ | 3,214 |  |  | $ | 3,205 |  |  | $ | 1,230 |  |  | $ | 1,429 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
AROs – nuclear and other | 1,179 |  |  | 945 |  |  | 1,127 |  |  | 884 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred fuel and purchased power | 2,486 |  |  | 3,866 |  |  | 1,173 |  |  | 2,060 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Accrued pension and OPEB | 2,389 |  |  | 2,336 |  |  | 757 |  |  | 759 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Storm cost securitized balance, net | 890 |  |  | 940 |  |  | 682 |  |  | 720 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Nuclear asset securitized balance, net | 830 |  |  | 881 |  |  | 830 |  |  | 881 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Debt fair value adjustment | 774 |  |  | 829 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Hedge costs deferrals | 749 |  |  | 378 |  |  | 323 |  |  | 128 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Storm cost deferrals | 407 |  |  | 687 |  |  | 298 |  |  | 559 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
COR regulatory asset | 371 |  |  | 221 |  |  | 337 |  |  | 221 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Post-in-service carrying costs (PISCC) and deferred operating expenses | 357 |  |  | 359 |  |  | 42 |  |  | 42 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Retired generation facilities | 275 |  |  | 316 |  |  | 220 |  |  | 243 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred asset – Lee and Harris COLA | 252 |  |  | 288 |  |  | 15 |  |  | 21 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Customer connect project | 251 |  |  | 271 |  |  | 125 |  |  | 136 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Advanced metering infrastructure (AMI) | 243 |  |  | 283 |  |  | 92 |  |  | 111 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Incremental COVID-19 expenses | 237 |  |  | 210 |  |  | 80 |  |  | 78 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Vacation accrual | 228 |  |  | 222 |  |  | 43 |  |  | 43 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Grid Deferral | 210 |  |  | 136 |  |  | 51 |  |  | 40 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Demand side management (DSM)/Energy efficiency (EE) | 201 |  |  | 189 |  |  | 191 |  |  | 188 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
CEP deferral | 193 |  |  | 190 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NCEMPA deferrals | 172 |  |  | 157 |  |  | 172 |  |  | 157 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Derivatives – natural gas supply contracts | 147 |  |  | 168 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred pipeline integrity costs | 133 |  |  | 121 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Nuclear deferral | 131 |  |  | 154 |  |  | 42 |  |  | 64 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
COR settlement | 115 |  |  | 120 |  |  | 30 |  |  | 32 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Decoupling | 115 |  |  | 42 |  |  | 15 |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred coal ash handling system costs | 86 |  |  | 92 |  |  | 21 |  |  | 25 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Qualifying facility contract buyouts | 68 |  |  | 81 |  |  | 68 |  |  | 81 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Network Integration Transmission Services deferral | 31 |  |  | 23 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Transmission expansion obligation | 30 |  |  | 31 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
East Bend deferrals | 28 |  |  | 33 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Propane caverns | 26 |  |  | 26 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Tennessee ARM Deferral | 20 |  |  | 3 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other | 428 |  |  | 327 |  |  | 127 |  |  | 77 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total regulatory assets | 17,266 |  |  | 18,130 |  |  | 8,091 |  |  | 8,979 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Less: Current portion | 3,648 |  |  | 3,485 |  |  | 1,661 |  |  | 1,833 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total noncurrent regulatory assets | $ | 13,618 |  |  | $ | 14,645 |  |  | $ | 6,430 |  |  | $ | 7,146 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Regulatory Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net regulatory liability related to income taxes | $ | 5,901 |  |  | $ | 6,462 |  |  | $ | 2,008 |  |  | $ | 2,192 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
COR regulatory liability | 5,497 |  |  | 5,151 |  |  | 2,805 |  |  | 2,269 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
AROs – nuclear and other | 1,673 |  |  | 1,038 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Hedge cost deferrals | 443 |  |  | 683 |  |  | 208 |  |  | 252 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Accrued pension and OPEB | 266 |  |  | 211 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred fuel and purchased power | 137 |  |  | 35 |  |  | 14 |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
DSM/EE | 89 |  |  | 88 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
DOE Settlement | 32 |  |  | 154 |  |  | 32 |  |  | 154 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Provision for rate refunds | 15 |  |  | 78 |  |  | 4 |  |  | 28 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other | 1,355 |  |  | 1,148 |  |  | 430 |  |  | 434 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total regulatory liabilities | 15,408 |  |  | 15,048 |  |  | 5,501 |  |  | 5,329 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Less: Current portion | 1,369 |  |  | 1,466 |  |  | 418 |  |  | 576 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total noncurrent regulatory liabilities | $ | 14,039 |  |  | $ | 13,582 |  |  | $ | 5,083 |  |  | $ | 4,753 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
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 securitized balance, net. Represents the North Carolina portion of storm restoration expenditures related to Hurricane Florence, Hurricane Michael, Hurricane Dorian and Winter Storm Diego (2018 and 2019 events). 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 to state the carrying value of Progress Energy and Piedmont at fair value in connection with the 2012 and 2016 mergers, respectively. Amount is amortized over the life of the related debt. Hedge costs deferrals. Amounts relate to unrealized gains and losses on derivatives recorded as a regulatory asset or liability, respectively, until the contracts are settled. Storm cost deferrals. Represents deferred incremental costs incurred related to major weather-related events. 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. Post-in-service carrying costs (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 ensuring 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. TN ARM Deferral. Represents amounts to be recovered for uncollected revenue for 2022 and deferred depreciation and carrying costs on the portion of capital expenditures placed in service but not yet reflected in rates. Net regulatory liability related to income taxes. Amounts for all registrants include regulatory liabilities related primarily to impacts from 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 the future removal of property, plant and equipment from retired or abandoned sites as property is retired. Also includes certain deferred gains on NDTF investments. DOE Settlement. Represents litigation settlement funds received resulting from the DOE’s failure to accept spent nuclear fuel and other radioactive waste from the Crystal River Unit 3 during 2014-2018 as required under the Nuclear Waste Policy Act. Provision for rate refunds. Represents estimated amounts due to customers based on recording interim rates subject to refund. 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, 2023. 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, 2023. 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. The FERC also regulates certification and siting of new interstate natural gas pipeline projects. Duke Energy Carolinas and Duke Energy Progress Hurricane Ian In late September and early October 2022, Hurricane Ian inflicted severe damage to the Duke Energy Carolinas and Duke Energy Progress ter ritories in North Carolina and South Carolina. Approximately 950,000 customers were impacted. As of December 31, 2023, total estimated operation and maintenance expenses incurred for restoration efforts were approximately $95 million, with an additional $8 million in capital investments. Approximately $87 million of the operation and maintenance expenses are deferred in Regulatory assets within Other Noncurrent Assets on the Consolidated Balance Sheets as of December 31, 2023 ($32 million and $55 million for Duke Energy Carolinas and Duke Energy Progress, respectively), Duke Energy Carolinas and Duke Energy Progr ess have regulatory tools to recover storm costs including deferral and securitization. These estimates could change as Duke Energy Carolinas and Duke Energy Progress receive additional information on actual costs. 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) | 2023 | 2022 |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
AROs – coal ash | $ | 1,559 |  | $ | 1,391 |  |  | (g) | (b)
Deferred fuel and purchased power(i) | 1,293 |  | 1,614 |  |  | (e) | 2025
Accrued pension and OPEB | 671 |  | 614 |  |  |  | (h)
Storm cost securitized balance, net | 208 |  | 220 |  |  | Yes | 2041
Hedge costs deferrals | 405 |  | 228 |  |  |  | (b)
Storm cost deferrals | 97 |  | 114 |  |  | Yes | (b)
PISCC and deferred operating expenses | 48 |  | 47 |  |  | Yes | (b)
Retired generation facilities(c) | 26 |  | 39 |  |  | Yes | (b)
Deferred asset – Lee COLA | 237 |  | 267 |  |  |  | (b)
Customer connect project(c) | 58 |  | 62 |  |  | Yes | (b)
AMI(c) | 125 |  | 139 |  |  | Yes | (b)
Incremental COVID-19 expenses | 152 |  | 127 |  |  | Yes | (b)
Vacation accrual | 87 |  | 84 |  |  |  | 2024
Grid Deferral(c) | 159 |  | 96 |  |  | Yes | (b)
Nuclear deferral | 89 |  | 90 |  |  |  | 2025
COR settlement(c) | 85 |  | 88 |  |  | Yes | (b)
Deferred coal ash handling system costs(c) | 65 |  | 67 |  |  | Yes | (b)
Other | 116 |  | 101 |  |  |  | (b)
Total regulatory assets | 5,480 |  | 5,388 |  |  |  |
Less: Current portion | 1,564 |  | 1,095 |  |  |  |
Total noncurrent regulatory assets | $ | 3,916 |  | $ | 4,293 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
Net regulatory liability related to income taxes(d) | $ | 2,200 |  | $ | 2,475 |  |  | Yes | (b)
COR regulatory liability(c) | 1,641 |  | 1,769 |  |  | Yes | (f)
AROs – nuclear and other | 1,673 |  | 1,038 |  |  |  | (b)
Hedge cost deferrals | 158 |  | 350 |  |  |  | (b)
Accrued pension and OPEB | 106 |  | 44 |  |  |  | (h)
Deferred fuel and purchased power(i) | 85 |  | — |  |  | (e) | 2025
DSM/EE(c) | 87 |  | 86 |  |  | Yes | (j)
Provision for rate refunds(c) | 11 |  | 50 |  |  | Yes | (b)
Other | 616 |  | 501 |  |  |  | (b)
Total regulatory liabilities | 6,577 |  | 6,313 |  |  |  |
Less: Current portion | 587 |  | 530 |  |  |  |
Total noncurrent regulatory liabilities | $ | 5,990 |  | $ | 5,783 |  |  |  |
(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) 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) Earns a debt and equity return on coal ash expenditures for North Carolina and South Carolina retail customers as permitted by various regulatory orders. (h) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail. (i) Duke Energy Carolinas submitted a fuel filing to the NCUC in February 2023 for recovery of $998 million, which included deferrals through December 2022. The NCUC approved recovery of this balance through December 2024. The next filing will be made in the first quarter of 2024. Duke Energy Carolinas submitted a fuel filing to the PSCSC in August 2023 for recovery of $310 million, which included deferrals through May 2023. The PSCSC approved recovery of this balance through October 2024. The next filing will be made in the third quarter of 2024. (j) Includes incentives on DSM/EE investments and is recovered or refunded through an annual rider mechanism. 2023 North Carolina Rate Case On January 19, 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 HB 951. The application as originally filed requested an overall retail revenue increase of $501 million in Year 1, $172 million in Year 2 and $150 million in Year 3, for a combined total of $823 million or 15.7% by early 2026. The rate increase is driven primarily by transmission and distribution investments since the last rate case and projected in the MYRP, as well as investments in energy storage and solar assets included in the MYRP consistent with the Carbon Plan. On August 22, 2023, Duke Energy Carolinas filed with the NCUC a partial settlement with the 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 Public Staff resolving additional issues, including the future treatment of nuclear production tax credits related to the Inflation Reduction Act, through a stand-alone rider that will provide the benefits to customers 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 a capital structure of 53% equity and 47% debt 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, subject to refund, on September 1, 2023. New revised Year 1 rates and the residential decoupling were implemented on January 15, 2024. On February 13, 2024, a number of parties filed Notices of Appeal of the December 15, 2023 NCUC order. Appeals were filed by the Carolina Industrial Group for Fair Utility Rates (CIGFUR) III, a collection of various electric membership corporations (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. Duke Energy Carolinas cannot predict the outcome of this matter. 2024 South Carolina Rate Case On January 4, 2024, Duke Energy Carolinas filed a rate case with the PSCSC to request an average effective net increase in annual retail revenues of 11.4%, or approximately $239 million, in the first two years, and an additional overall effective increase of about 4.1%, or approximately $84 million additional revenue, after the first two years. The requested increases, if approved, would result in an overall average 15.5% increase in annual retail revenues, or approximately $323 million, prior to mitigation efforts. To mitigate the rate increase, Duke Energy Carolinas has proposed to accelerate the return of remaining federal unprotected EDIT balances to customers over two years. This offset reduces the impact to customers in the first two years to the effective net increase of 11.4%, after which the credit for EDIT balances expire. Duke Energy Carolinas has requested the revised rates to be effective no later than August 1, 2024. The evidentiary hearing is scheduled to commence on May 20, 2024. Duke Energy Carolinas cannot predict the outcome of this matter. 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) | 2023 | 2022 |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
AROs – coal ash | $ | 1,218 |  | $ | 1,418 |  |  | (g) | (b)
AROs – nuclear and other | 1,110 |  | 869 |  |  |  | (c)
Deferred fuel and purchased power(l) | 579 |  | 705 |  |  | (e) | 2025
Accrued pension and OPEB | 408 |  | 417 |  |  |  | (j)
Storm cost securitized balance, net | 682 |  | 720 |  |  | Yes | 2041
Hedge costs deferrals | 260 |  | 55 |  |  |  | (b)
Storm cost deferrals | 228 |  | 234 |  |  | Yes | (b)
PISCC and deferred operating expenses | 42 |  | 42 |  |  | Yes | 2054
Retired generation facilities(d) | 126 |  | 149 |  |  | Yes | (b)
Deferred asset – Harris COLA | 15 |  | 21 |  |  |  | (b)
Customer connect project(d) | 49 |  | 54 |  |  | Yes | (b)
AMI(d) | 68 |  | 81 |  |  | Yes | (b)
Incremental COVID-19 expenses | 80 |  | 78 |  |  |  | (b)
Vacation accrual | 43 |  | 43 |  |  |  | 2024
Grid Deferral(d) | 51 |  | 40 |  |  | Yes | (b)
DSM/EE(d) | 182 |  | 180 |  |  | Yes | (h)
NCEMPA deferrals(d) | 172 |  | 157 |  |  | (f) | 2042
Nuclear deferral | 42 |  | 64 |  |  |  | 2025
COR settlement(d) | 30 |  | 32 |  |  | Yes | (b)
Decoupling | 15 |  | — |  |  | Yes | (b)
Deferred coal ash handling system costs(d) | 21 |  | 25 |  |  | Yes | (b)
Other | 67 |  | 30 |  |  |  | (b)
Total regulatory assets | 5,488 |  | 5,414 |  |  |  |
Less: Current portion | 942 |  | 690 |  |  |  |
Total noncurrent regulatory assets | $ | 4,546 |  | $ | 4,724 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
Net regulatory liability related to income taxes(k) | $ | 1,420 |  | $ | 1,559 |  |  | Yes | (b)
COR regulatory liability | 2,805 |  | 2,269 |  |  |  | (i)
Hedge cost deferrals | 87 |  | 252 |  |  |  | (b)
Deferred fuel and purchased power(l) | 14 |  | — |  |  | (e) | 2025
Provision for rate refunds(d) | 4 |  | 28 |  |  | Yes | (b)
Other | 345 |  | 344 |  |  |  | (b)
Total regulatory liabilities | 4,675 |  | 4,452 |  |  |  |
Less: Current portion | 300 |  | 332 |  |  |  |
Total noncurrent regulatory liabilities | $ | 4,375 |  | $ | 4,120 |  |  |  |
(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) Earns a debt and equity return on coal ash expenditures for North Carolina and South Carolina retail customers as permitted by various regulatory orders. (h) Includes incentives on DSM/EE investments and is recovered through an annual rider mechanism. (i) Recovered over the life of the associated assets. (j) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail. (k) 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. (l) Duke Energy Progress submitted a fuel filing to the NCUC in June 2023 for recovery of $445 million, which included deferrals through March 2023. The NCUC approved recovery of this balance through November 2024. The next filing will be made in the second quarter of 2024. Duke Energy Progress submitted a fuel filing to the PSCSC in May 2023 for recovery of $79 million, which included deferrals through February 2023. The PSCSC approved recovery of this balance through July 2024. The next filing will be made in the second quarter of 2024. 2022 North Carolina Rate Case On October 6, 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 HB 951. The overall retail revenue increase as originally filed would have been $326 million in Year 1, $151 million in Year 2 and $138 million in Year 3, for a combined total of $615 million, by late 2025. The rate increase is driven primarily by transmission and distribution investments since the last rate case and projected in the MYRP, as well as investments in energy storage and solar assets included in the MYRP consistent with the Carbon Plan. On April 26, 2023, Duke Energy Progress filed with the NCUC a partial settlement with 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 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 a capital structure of 53% equity and 47% debt 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 Operations, maintenance and other, for the year ended December 31, 2023, on the Consolidated Statements of Operations. Duke Energy Progress implemented interim rates, subject to refund, on June 1, 2023, and implemented revised Year 1 rates and the residential decoupling on October 1, 2023. On October 17, 2023, CIGFUR II and Haywood Electric Membership Corporation each filed a Notice of Appeal and Exceptions to the Supreme Court of North Carolina. Both parties were appealing 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. On November 6, 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. On November 9, 2023, Du ke Energy Progress, the 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. Duke Energy Progress cannot predict the outcome of this matter. 2023 South Carolina Storm Securitization On May 31, 2023, Duke Energy Progress filed a petition with the PSCSC requesting authorization for the financing of Duke Energy Progress' storm recovery costs in the amount of approximately $171 million, through securitization, due to storm recovery activities required as a result of the following storms: Pax, Ulysses, Matthew, Florence, Michael, Dorian, Izzy and Jasper. On September 8, 2023, Duke Energy Progress filed a comprehensive settlement agreement with all parties on all cost recovery issues raised in the storm securitization proceeding. The evidentiary hearing occurred in early September 2023. On September 20, 2023, the PSCSC approved the comprehensive settlement agreement and on October 13, 2023, the PSCSC issued its financing order. Duke Energy Progress will proceed with structuring, marketing and pricing the storm recovery bonds and then seek PSCSC authorization to issue the bonds in the first half of 2024. Duke Energy Progress cannot predict the outcome of this matter. 2022 South Carolina Rate Case On September 1, 2022, Duke Energy Progress filed an application with the PSCSC to request an increase in base rate retail revenues. On J anuary 12, 2023, Duke Energy Progress and the ORS, as well as other consumer, environmental, and industrial intervening parties, filed a comprehensive Agreement and Stipulation of Settlement resolving all issues in the base rate proceeding. The major components of the stipulation include: •A $52 million annual customer rate increase prior to the reduction from the accelerated return to customers of federal unprotected Property, Plant and Equipment related EDIT. After extending the remaining EDIT giveback to customers to 33 months, the net annual retail rate increase is approximately $36 million. •ROE of 9.6% based upon a capital structure of 52.43% equity and 47.57% debt. •Continuation of deferral treatment of coal ash basin closure costs. Supports an amortization period for remaining coal ash closure costs in this rate case of seven years. Duke Energy Progress agreed not to seek recovery of approximately $50 million of deferred coal ash expenditures related to retired sites in this rate case (South Carolina retail allocation). •Accepts the 2021 Depreciation Study as proposed in this case, as adjusted for certain recommendations from ORS and includes accelerated retirement dates for certain coal units as originally proposed. •Establishment of a storm reserve to help offset the costs of major storms. The PSCSC held a hearing on January 17, 2023, to consider evidence supporting the stipulation and unanimously voted to approve the comprehensive agreement on February 9, 2023. A final written order was issued on March 8, 2023. New rates went into effect April 1, 2023. 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) | 2023 | 2022 |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
AROs – coal ash | $ | 12 |  | $ | 11 |  |  |  | (b)
AROs – nuclear and other | 17 |  | 15 |  |  |  | (b)
Deferred fuel and purchased power(g) | 594 |  | 1,355 |  |  | (e) | 2024
Accrued pension and OPEB(c) | 349 |  | 342 |  |  | Yes | (f)
Nuclear asset securitized balance, net | 830 |  | 881 |  |  |  | 2036
Hedge costs deferrals(c) | 63 |  | 73 |  |  | Yes | 2038
Storm cost deferrals(c) | 70 |  | 325 |  |  | (e) | (b)
COR regulatory asset | 337 |  | 221 |  |  | (d) | (b)
Retired generation facilities(c) | 94 |  | 94 |  |  | Yes | 2044
Customer connect project(c) | 76 |  | 82 |  |  | Yes | 2037
AMI(c) | 24 |  | 30 |  |  | Yes | 2032
Qualifying facility contract buyouts(c) | 68 |  | 81 |  |  | Yes | 2034
Other | 69 |  | 55 |  |  | (d) | (b)
Total regulatory assets | 2,603 |  | 3,565 |  |  |  |
Less: Current portion | 720 |  | 1,143 |  |  |  |
Total noncurrent regulatory assets | $ | 1,883 |  | $ | 2,422 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
Net regulatory liability related to income taxes(c) | $ | 588 |  | $ | 633 |  |  |  | (b)
Hedge cost deferrals | 121 |  | — |  |  |  | (b)
DOE Settlement | 32 |  | 154 |  |  |  | 2024
Other | 85 |  | 90 |  |  | (d) | (b)
Total regulatory liabilities | 826 |  | 877 |  |  |  |
Less: Current portion | 118 |  | 244 |  |  |  |
Total noncurrent regulatory liabilities | $ | 708 |  | $ | 633 |  |  |  |
(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. (g) On March 6, 2023, the FPSC approved Duke Energy Florida's amended February 2023 fuel filing recovery of $469 million, which included the 2022 actual under-recovery of $1.2 billion, offset by projected declining fuel costs in 2023 due to lower natural gas prices. The approved 21-month recovery period for the actual 2022 under-recovery is April 2023 through December 2024; the reduction in 2023 fuel costs were approved to be returned over 9-months from April 2023 through December 2023. Duke Energy Florida made its most recent fuel filing in September 2023. On November 1, 2023, the FPSC approved Duke Energy Florida's September 2023 fuel filing, which included the proposed fuel factors for 2024. In addition to the under-recoveries approved above, that filing also included a re-projected 2023 over-recovery of approximately $120 million that will be returned to customers January 2024 through December 2024. 2021 Settlement Agreement On January 14, 2021, Duke Energy Florida filed the 2021 Settlement with the FPSC. The parties to the 2021 Settlement include Duke Energy Florida, the Office of Public Counsel (OPC), the Florida Industrial Power Users Group, White Springs Agricultural Chemicals, Inc. d/b/a PCS Phosphate and NUCOR Steel Florida, Inc. (collectively, the Parties). Pursuant to the 2021 Settlement, the Parties agreed to a base rate stay-out provision that expires year-end 2024; however, Duke Energy Florida is allowed an increase to its base rates of an incremental $67 million in 2022, $49 million in 2023 and $79 million in 2024, subject to adjustment in the event of tax reform during the years 2021, 2022 and 2023. The Parties also agreed to an ROE band of 8.85% to 10.85% with a midpoint of 9.85% based on a capital structure of 53% equity and 47% debt. The ROE band can be increased by 25 basis points if the average 30-year U.S. Treasury rate increases 50 basis points or more over a six-month period in which case the midpoint ROE would rise from 9.85% to 10.10%. On July 25, 2022, this provision was triggered. Duke Energy Florida filed a petition with the FPSC on August 12, 2022, to increase the ROE effective August 2022 with a base rate increase effective January 1, 2023. The FPSC approved this request on October 4, 2022. The 2021 Settlement also provided that Duke Energy Florida will be able to retain $173 million of the expected DOE award from its lawsuit to recover spent nuclear fuel to mitigate customer rates over the term of the 2021 Settlement. In return, Duke Energy Florida is permitted to recognize the $173 million into earnings through the approved settlement period. Duke Energy Florida settled the DOE lawsuit and received payment of approximately $180 million on June 15, 2022, of which the retail portion was approximately $154 million. The 2021 Settlement authorizes Duke Energy Florida to collect the difference between $173 million and the $154 million retail portion of the amount received through the capacity cost recovery clause. As of December 31, 2023, Duke Energy Florida has recognize d $141 million into earnings. The remaining $32 million is expected to be recognized in 2024, while also remaining within the approved return on equity band. The 2021 Settlement also contained a provision to recover or flow-back the effects of tax law changes. As a result of the IRA enacted on August 16, 2022, Duke Energy Florida is eligible for PTCs associated with solar facilities placed in service beginning in January 2022. Duke Energy Florida filed a petition with the FPSC on October 17, 2022, to reduce base rates effective January 1, 2023, by $56 million to flow back the expected 2023 PTCs and to flow back the expected 2022 PTCs via an adjustment to the capacity cost recovery clause. On December 14, 2022, the FPSC issued an order approving Duke Energy Florida’s petition. See Note 24 for additional information on the IRA. In addition to these terms, the 2021 Settlement contained provisions related to the accelerated depreciation of Crystal River Units 4-5, the approval of approximately $1 billion in future investments in new cost-effective solar power, the implementation of a new Electric Vehicle Charging Station Program and the deferral and recovery of costs in connection with the implementation of Duke Energy Florida’s Vision Florida program, which explores various emerging non-carbon emitting generation technology, distributed technologies and resiliency projects, among other things. The 2021 Settlement also resolved remaining unrecovered storm costs for Hurricane Michael and Hurricane Dorian. The FPSC approved the 2021 Settlement on May 4, 2021, issuing an order on June 4, 2021. Revised customer rates became effective January 1, 2022, with subsequent base rate increases effective January 1, 2023, and January 1, 2024. Clean Energy Connection On July 1, 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 approximately 750 MW. The program allows 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 estimated cost of the 10 new solar generation facilities is approximately $1 billion and the projects are expected to be completed by the end of 2024. This investment will be included in base rates offset by the revenue from the subscription fees and the credits will be included for recovery in the fuel cost recovery clause. The FPSC approved the program in January 2021. On February 24, 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. The Supreme Court of Florida heard oral arguments in the appeal on February 9, 2022. 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. On September 23, 2022, the FPSC issued a revised order and submitted it on September 26, 2022, to the Supreme Court of Florida. The Supreme Court of Florida requested that the parties file supplemental briefs regarding the revised order, which were filed February 6, 2023. LULAC has filed a request for Oral Argument on the issues discussed in the supplemental briefs, but the Court has yet to rule on that request. The FPSC approval order remains in effect pending the outcome of the appeal. Duke Energy Florida cannot predict the outcome of this matter. Storm Protection Plan On April 11, 2022, Duke Energy Florida filed a Storm Protection Plan for approval with the FPSC. The plan, which covers investments for the 2023-2032 time frame, reflects approximately $7 billion of capital investment in transmission and distribution meant to strengthen its infrastructure, reduce outage times associated with extreme weather events, reduce restoration costs and improve overall service reliability. The evidentiary hearing began on August 2, 2022. On October 4, 2022, the FPSC voted to approve Duke Energy Florida's plan with one modification to remove the transmission loop radially fed program, representing a reduction of approximately $80 million over the 10-year period starting in 2025. On December 9, 2022, the OPC filed a notice of appeal of this order to the Florida Supreme Court. The OPC's initial brief was filed on April 18, 2023. Duke Energy Florida filed its answer brief on July 17, 2023. The OPC's reply brief was filed on October 16, 2023. The Florida Supreme Court heard oral arguments on February 7, 2024. Duke Energy Florida cannot predict the outcome of this matter. Hurricanes Ian and Idalia On September 28, 2022, much of Duke Energy Florida’s service territory was impacted by Hurricane Ian, which caused significant damage resulting in more than 1.1 million outages. Duke Energy Florida's Consolidated Balance Sheets included an estimate of approximately $353 million as of December 31, 2022, related to deferred Hurricane Ian storm costs, consistent with the FPSC's storm rule, in Regulatory assets within Other Noncurrent Assets. After depleting any existing storm reserves, which were approximately $107 million before Hurricane Ian, Duke Energy Florida is permitted to petition the FPSC for recovery of additional incremental operation and maintenance costs resulting from the storm and to replenish the retail customer storm reserve to approximately $132 million. Duke Energy Florida filed its petition for cost recovery of various storms, including Hurricane Ian, and replenishment of the storm reserve on January 23, 2023, seeking recovery of $442 million, for recovery over 12 months beginning with the first billing cycle in April 2023. On March 7, 2023, the FPSC approved this request for interim recovery, subject to refund, and ordered Duke Energy Florida to file documentation of the total actual storm costs, once known. Duke Energy Florida filed documentation evidencing its total actual storm costs of $431 million on September 29, 2023. The FPSC will hold a final hearing to determine the prudence of these costs in May of 2024. On August 30, 2023, Hurricane Idalia made landfall on Florida’s gulf coast, causing damage and impacting more than 200,000 customers across Duke Energy Florida's service territory. Duke Energy Florida's December 31, 2023, Consolidated Balance Sheets includes an estimate of approximately $102 million in Regulatory Assets within Current Assets related to deferred Hurricane Idalia storm costs consistent with the FPSC's storm rule. On October 16, 2023, Duke Energy Florida requested to combine the $92 million retail portion of the deferred estimated Hurricane Idalia costs with $74 million of costs projected to be collected after December 31, 2023, under the existing approved storm cost recovery and storm surcharge. This $74 million of costs relates primarily to the approved ongoing replenishment of the storm reserves. At its December 5, 2023 Agenda Conference, the FPSC approved recovery of the total $166 million over 12 months beginning with its first billing cycle in January 2024, replacing the previously approved storm cost recovery and storm surcharge, and ordered Duke Energy Florida to file documentation of the total actual Idalia related storm costs, once known. Revised rates were effective January 1, 2024. Duke Energy Florida cannot predict the outcome of these matters. 2024 Florida Rate Case In January 2024, Duke Energy Florida notified the FPSC that it expects to file a formal request for new base rates in April 2024. Duke Energy Florida intends to propose 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 will propose 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. Duke Energy Florida expects to request additional base rate revenue requirements of approximately $596 million in 2025, $95 million in 2026 and $127 million in 2027, representing an average annual increase in revenue requirements of approximately 4% over 2025 through 2027. 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) | 2023 | 2022 |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
AROs – coal ash | $ | 17 |  | $ | — |  |  | Yes | (b)
Deferred fuel and purchased gas costs | 20 |  | 54 |  |  |  | 2024
Accrued pension and OPEB | 123 |  | 129 |  |  |  | (e)
Storm cost deferrals | 12 |  | 14 |  |  |  | 2024
COR regulatory asset | 34 |  | — |  |  |  | (b)
PISCC and deferred operating expenses(c) | 15 |  | 15 |  |  | Yes | 2083
Customer connect project | 49 |  | 54 |  |  |  | (b)
AMI | 13 |  | 18 |  |  |  | (b)
CEP deferral | 193 |  | 190 |  |  | Yes | (b)
Deferred pipeline integrity costs | 30 |  | 28 |  |  | Yes | (b)
Decoupling | 25 |  | — |  |  |  | (b)
Network Integration Transmission Services deferral | 31 |  | 23 |  |  | Yes | (b)
Transmission expansion obligation | 30 |  | 31 |  |  |  | (b)
East Bend deferrals(c) | 28 |  | 33 |  |  | Yes | (b)
Propane caverns | 26 |  | 26 |  |  |  | (b)
Other | 103 |  | 69 |  |  |  | (b)
Total regulatory assets | 749 |  | 684 |  |  |  |
Less: Current portion | 73 |  | 103 |  |  |  |
Total noncurrent regulatory assets | $ | 676 |  | $ | 581 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
Net regulatory liability related to income taxes | $ | 466 |  | $ | 496 |  |  |  | (b)
COR regulatory liability | — |  | 9 |  |  |  | (d)
Accrued pension and OPEB | 17 |  | 21 |  |  |  | (e)
Deferred fuel and purchased gas costs | 15 |  | 35 |  |  |  | 2024
Other | 55 |  | 72 |  |  |  | (b)
Total regulatory liabilities | 553 |  | 633 |  |  |  |
Less: Current portion | 56 |  | 99 |  |  |  |
Total noncurrent regulatory liabilities | $ | 497 |  | $ | 534 |  |  |  |
(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) 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 Electric Base Rate Case Duke Energy Ohio filed with the PUCO an electric distribution base rate case application on October 1, 2021, with supporting testimony filed on October 15, 2021, requesting an increase in electric distribution base rates of approximately $55 million. On September 19, 2022, Duke Energy Ohio filed a Stipulation and Recommendation with the PUCO, which included an increase in overall electric distribution base rates of approximately $23 million with an equity ratio of 50.5% and an ROE of 9.5%. The stipulation was among all but one party to the proceeding. The PUCO issued an order on December 14, 2022, approving the Stipulation without modification. Rates went into effect on January 3, 2023. The Ohio Consumers' Counsel (OCC) filed an application for rehearing on January 13, 2023, arguing the Stipulation was unreasonable, discriminatory and denied OCC due process. On February 8, 2023, the Commission granted the OCC's application for rehearing for further consideration. Duke Energy Ohio cannot predict the outcome of this matter. Energy Efficiency Cost Recovery In response to changes in Ohio law that eliminated Ohio's energy efficiency mandates, the PUCO issued an order on February 26, 2020, directing utilities to wind down their demand-side management programs by September 30, 2020, and to terminate the programs by December 31, 2020. •On March 27, 2020, Duke Energy Ohio filed an application for rehearing seeking clarification on the final true up and reconciliation process after 2020. •Effective January 1, 2021, Duke Energy Ohio suspended its energy efficiency programs. On August 9, 2023, the PUCO issued its decision approving the Company’s request for recovery and final true up of energy efficiency program costs, lost distribution revenues and performance incentives from calendar years 2018 through 2020, resulting in $14 million of Regulated electric revenue on the Consolidated Statements of Operations for the year ended December 31, 2023, and resolving all outstanding issues in these proceedings. Revised rates were effective September 1, 2023. Duke Energy Ohio Natural Gas Base Rate Case Duke Energy Ohio filed with the PUCO a natural gas base rate case application on June 30, 2022, with supporting testimony filed on July 14, 2022, requesting an increase in natural gas base rates of approximately $49 million. The drivers for this case are 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. On April 28, 2023, Duke Energy Ohio filed a stipulation with all parties to the case except the 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 on May 24, 2023. On November 1, 2023, PUCO issued an order approving the stipulation as filed. New rates went into effect November 1, 2023. On December 1, 2023, the OCC filed an application for rehearing. On December 13, 2023, the PUCO granted OCC's application for rehearing for further consideration of issues raised. Duke Energy Ohio cannot predict the outcome of this matter. MGP Cost Recovery In an order issued in 2013, the PUCO approved Duke Energy Ohio's deferral and recovery of costs related to environmental remediation at two sites (East End and West End) that housed former MGP operations. Duke Energy Ohio made annual applications with the PUCO to recover its incremental remediation costs consistent with the PUCO’s directive in Duke Energy Ohio’s 2012 natural gas base rate case. A Stipulation and Recommendation was filed jointly by Duke Energy Ohio, the Staff, the Office of the Ohio Consumers' Counsel and the Ohio Energy Group on August 31, 2021, which was approved without modification by the PUCO on April 20, 2022. T he Stipulation and Recommendation resolved all open issues regarding MGP remediation costs incurred between 2013 and 2019, Duke Energy Ohio’s request for additional deferral authority beyond 2019 and the pending issues related to the Tax Act described below as it related to Duke Energy Ohio’s natural gas operations. As a result of the approval of the Stipulation and Recommendation, Duke Energy Ohio recognized pretax charges of approximately $15 million to Operating revenues, regulated natural gas and $58 million to Operation, maintenance and other and a tax benefit of $72 million to Income Tax (Benefit) Expense in the Consolidated Statements of Operations for the year ended December 31, 2022. The Stipulation and Recommendation further acknowledged Duke Energy Ohio’s ability to file a request for additional deferral authority in the future related to environmental remediation of any MGP impacts in the Ohio River, if necessary, subject to specific conditions. On June 15, 2022, the PUCO granted the rehearing requests of Interstate Gas Supply, Inc. (IGS) and The Retail Energy Supply Association (RESA), which were filed on May 20, 2022, for further consideration. Duke Energy Ohio cannot predict the outcome of this matter. Tax Act – Ohio On December 21, 2018, Duke Energy Ohio filed an application to change its base rate tariffs and establish a rider to implement the benefits of the Tax Act for natural gas customers. The rider would flow through to customers the benefit of the reduction in the statutory federal tax rate from 35% to 21% since January 1, 2018, all future benefits of the lower tax rates and a full refund of deferred income taxes collected at the higher tax rates in prior years. Deferred income taxes subject to normalization rules would be refunded consistent with federal law and deferred income taxes not subject to normalization rules will be refunded over a 10-year period. An evidentiary hearing occurred on August 7, 2019. The Stipulation and Recommendation filed on August 31, 2021, and approved on April 20, 2022, disclosed in the MGP Cost Recovery matter above, resolved the outstanding issues in this proceeding by providing customers a one-time bill credit for the reduction in the statutory federal tax rate from 35% to 21% since January 1, 2018, through June 1, 2022, and reducing base rates going forward. Deferred income taxes not sub ject to normalization rules were written off. Deferred income taxes subject to normalization rules are refunded consistent with federal law through a rider. The commission granted the rehearing requests of IGS and RESA for further consideration. Duke Energy Ohio cannot predict the outcome of this matter. Midwest Propane Caverns Duke Energy Ohio used propane stored in caverns to meet peak demand during winter for several decades. Once the Central Corridor Project was complete and placed in service, the propane peaking facilities were no longer necessary and were retired. On October 7, 2021, Duke Energy Ohio requested deferral treatment of the property, plant and equipment as well as costs related to propane inventory and decommissioning costs. On January 6, 2022, the Staff issued a report recommending deferral authority for costs related to propane inventory and decommissioning costs, but not for the net book value of the remaining plant assets. As a result of the Staff's report, Duke Energy Ohio recorded a $19 million charge to Impairment of assets and other charges on the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2021. A Stipulation and Recommendation was filed jointly by Duke Energy Ohio and the Staff on April 27, 2022, recommending, among other things, approval of deferral treatment of a portion of the net book value of the property, plant and equipment prior to the 2021 impairment at the time of the next natural gas base rate case, excluding operations and maintenance savings, decommissioning costs not to exceed $7 million and costs related to propane inventory. The Stipulation and Recommendation states that Duke Energy Ohio will seek recovery of the deferral through its next natural gas base rate case proceeding with a proposed amortization period of at least 10 years and include an independent engineering study analyzing the necessity and prudency of the incremental investments made at the facilities since March 31, 2012. Duke Energy Ohio will not seek a return on the deferred amounts. An evidentiary hearing was held on September 8, 2022. On October 5, 2022, the PUCO issued an order approving the Stipulation and Recommendation as filed. As a result of the order, Duke Energy Ohio recorded a reversal of $12 million to Impairment of assets and other charges on the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2022. Duke Energy Kentucky Electric Base Rate Case On December 1, 2022, Duke Energy Kentucky filed a rate case with the KPSC requesting an annualized increase in electric base rates of approximately $75 million. The request for rate increase was driven by capital investments to strengthen the electricity generation and delivery systems along with adjusted depreciation rates for the East Bend and Woodsdale generation stations to support the energy transition. Duke Energy Kentucky also requested 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. The Company's request to align the depreciation rates of East Bend with a 2035 retirement date was denied and the KPSC ordered depreciation rates with a 2041 retirement date for the unit. The KPSC did approve the request to align the depreciation rates of Woodsdale CT with a 2040 retirement date and denied the voluntary community-based renewable subscription program and the two electric vehicle charging programs. On November 1, 2023, Duke Energy Kentucky filed for rehearing requesting certain matters be reconsidered by the KPSC. On November 21, 2023, KPSC granted in part and denied in part the Company's request for rehearing. On February 15, 2024, the KPSC issued a briefing schedule for the rehearing process. Simultaneous briefs are due on March 18, 2024, simultaneous reply briefs are due on April 1, 2024 and the matter shall stand submitted on April 2, 2024. 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 including decommissioning costs in depreciation rates for East Bend and Woodsdale. On January 8, 2024, answers to the appeal were filed by the KPSC, Kentucky Attorney General, and the Kentucky Broadband & Cable Association. Duke Energy Kentucky cannot predict the outcome of this matter. 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) | 2023 | 2022 |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
AROs – coal ash | $ | 408 |  | $ | 385 |  |  | Yes | (b)
Deferred fuel and purchased power | — |  | 138 |  |  |  | 2024
Accrued pension and OPEB | 208 |  | 214 |  |  |  | (e)
Hedge costs deferrals | 19 |  | 20 |  |  |  | (b)
PISCC and deferred operating expenses(c) | 252 |  | 255 |  |  | Yes | (b)
Retired generation facilities(c) | 29 |  | 34 |  |  | Yes | 2030
Customer connect project | 19 |  | 19 |  |  |  | (b)
AMI | 13 |  | 15 |  |  |  | 2031
Other | 48 |  | 44 |  |  |  | (b)
Total regulatory assets | 996 |  | 1,124 |  |  |  |
Less: Current portion | 102 |  | 249 |  |  |  |
Total noncurrent regulatory assets | $ | 894 |  | $ | 875 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
Net regulatory liability related to income taxes | $ | 794 |  | $ | 840 |  |  |  | (b)
COR regulatory liability | 496 |  | 531 |  |  |  | (d)
Hedge cost deferrals | 77 |  | 81 |  |  |  | (b)
Accrued pension and OPEB | 109 |  | 104 |  |  |  | (e)
Deferred fuel and purchased power | 23 |  | — |  |  |  | 2024
Other | 169 |  | 85 |  |  |  | (b)
Total regulatory liabilities | 1,668 |  | 1,641 |  |  |  |
Less: Current portion | 209 |  | 187 |  |  |  |
Total noncurrent regulatory liabilities | $ | 1,459 |  | $ | 1,454 |  |  |  |
(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. 2019 Indiana Rate Case On July 2, 2019, Duke Energy Indiana filed a general rate case with the IURC for a rate increase for retail customers of approximately $395 million. The rebuttal case, filed on December 4, 2019, updated the requested revenue requirement to result in a 15.6% or $396 million average retail rate increase, including the impacts of the utility receipts tax. On June 29, 2020, the IURC issued an order in the rate case approving a revenue increase of $146 million before certain adjustments and ratemaking refinements. The order approved Duke Energy Indiana's requested forecasted rate base of $10.2 billion as of December 31, 2020, including the Edwardsport Integrated Gasification Combined Cycle (IGCC) Plant. The IURC reduced Duke Energy Indiana's request by slightly more than $200 million, when accounting for the utility receipts tax and other adjustments. Step one rates were estimated to be approximately 75% of the total rate increase and became effective on July 30, 2020. Step two rates estimated to be the remaining 25% of the total rate increase were approved on July 28, 2021, and implemented in August 2021. Several groups appealed the IURC order to the Indiana Court of Appeals. The Indiana Court of Appeals affirmed the IURC decision on May 13, 2021. However, upon appeal by the Indiana Office of Utility Consumer Counselor (OUCC) and the Duke Industrial Group on March 10, 2022, the Indiana Supreme Court found that the IURC erred in allowing Duke Energy Indiana to recover coal ash costs incurred before the IURC’s rate case order in June 2020. The Indiana Supreme Court found that allowing Duke Energy Indiana to recover coal ash costs incurred between rate cases that exceeded the amount built into base rates violated the prohibition against retroactive ratemaking. The IURC’s order was remanded to the IURC for additional proceedings consistent with the Indiana Supreme Court’s opinion. As a result of the court's opinion, Duke Energy Indiana recognized pretax charges of approximately $211 million to Impairment of assets and other charges and $46 million to Operating revenues in the Consolidated Statements of Operations for the year ended December 31, 2022. Duke Energy Indiana filed a request for rehearing with the Supreme Court on April 11, 2022, which the court denied on May 26, 2022. Duke Energy Indiana filed its testimony in the remand proceeding on August 18, 2022. On February 3, 2023, Duke Energy Indiana filed a settlement agreement reached with the OUCC and Duke Industrial Group, which includes an agreed amount of approximately $70 million of refunds to be paid to customers. The IURC approved this settlement agreement in its entirety on April 12, 2023. In June of 2023, Duke Energy Indiana commenced refunding the approximate $70 million to customers in accordance with the settlement agreement. Indiana Coal Ash Recovery In Duke Energy Indiana’s 2019 rate case, the IURC also opened a subdocket for post-2018 coal ash related expenditures. Duke Energy Indiana filed testimony on April 15, 2020, in the coal ash subdocket requesting recovery for the post-2018 coal ash basin closure costs for plans that have been approved by IDEM as well as continuing deferral, with carrying costs, on the balance. On November 3, 2021, the IURC issued an order allowing recovery for post-2018 coal ash basin closure costs for the plans that have been approved by IDEM, 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. As a result of the Indiana Court of Appeals' opinion, Duke Energy Indiana recognized a pretax charge of approximately $175 million to Impairment of assets and other charges for the year ended December 31, 2022. In the second quarter of 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 commission approved the Company's proposal to remove the costs from its rates and assessed simple interest of the refunds of 4.71%, beginning from when the costs were initially recovered from customers. Duke Energy Indiana filed a new petition under the amended version of the federal mandate statute for post-2018 coal ash closure costs for the remaining basins not included in the 2020 Indiana Coal Ash Recovery Case. An evidentiary hearing was held on January 25, 2024. Duke Energy Indiana cannot predict the outcome of this matter. TDSIC 2.0 On November 23, 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 addition, the IURC set up a subdocket to consider a targeted economic development project, which the IURC approved on March 2, 2022. On July 15, 2022, the OUCC filed a notice of appeal to the Indiana Court of Appeals in Duke Energy Indiana’s TDSIC 2.0 proceeding. An appellant brief was filed on October 28, 2022, and Duke Energy Indiana filed its responsive brief on December 28, 2022. 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. The Indiana Supreme Court granted transfer and held an oral argument on September 28, 2023. Duke Energy Indiana cannot predict the outcome of this matter. 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) | 2023 | 2022 |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
AROs – nuclear and other | $ | 26 |  | $ | 27 |  |  |  | (d)
Accrued pension and OPEB(c) | 129 |  | 119 |  |  |  | (g)
Vacation accrual | 13 |  | 12 |  |  |  | 2024
Derivatives – natural gas supply contracts(f) | 147 |  | 168 |  |  |  |
Deferred pipeline integrity costs(c) | 103 |  | 93 |  |  |  | 2025
Decoupling | 75 |  | 42 |  |  | (e) | (b)
Tennessee ARM Deferral | 20 |  | 3 |  |  | (e) | (b)
Other | 58 |  | 47 |  |  | (e) | (b)
Total regulatory assets | 571 |  | 511 |  |  |  |
Less: Current portion | 161 |  | 119 |  |  |  |
Total noncurrent regulatory assets | $ | 410 |  | $ | 392 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
Net regulatory liability related to income taxes | $ | 433 |  | $ | 459 |  |  |  | (b)
COR regulatory liability(c) | 555 |  | 573 |  |  |  | (d)
Other | 98 |  | 66 |  |  | (e) | (b)
Total regulatory liabilities | 1,086 |  | 1,098 |  |  |  |
Less: Current portion | 98 |  | 74 |  |  |  |
Total noncurrent regulatory liabilities | $ | 988 |  | $ | 1,024 |  |  |  |
(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. Current contracts extend into 2031. (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. Tennessee Annual Review Mechanism On October 10, 2022, the TPUC approved Piedmont’s petition to adopt an ARM as allowed by Tennessee law. Under the ARM, Piedmont will adjust rates annually to achieve its allowed 9.80% ROE over the upcoming year and to true up any variance between its allowed ROE and actual ROE from the prior calendar year. The initial year subject to the true up was 2022, and Piedmont filed the initial rate adjustments request on May 19, 2023, for a total increase of approximately $42 million. On September 11, 2023, the TPUC approved a settlement between Piedmont and the Consumer Advocate Division of the Tennessee Attorney General's Office, which provided for recovery of the Historic Base Period Reconciliation cost of service of $11 million through rider rates and an increase in Piedmont's base rates of $29 million for the Annual Base Rate Reset component of the ARM. These amounts result in a total increase of $40 million with adjusted rates effective October 1, 2023. 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. IRPs filed by certain Subsidiary Registrants included planning assumptions around future retirement dates of aging coal-fired generating facilities in North Carolina (Duke Energy Carolinas and Duke Energy Progress) and Indiana (Duke Energy Indiana). In North Carolina, the NCUC concluded in its December 2022 Carbon Plan order that the projected retirement dates presented by Duke Energy Carolinas and Duke Energy Progress in their Carbon Plan for 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. Duke Energy Carolinas and Duke Energy Progress filed updated Resource Plans (Carbon Plan and IRP) in August 2023, and a supplemental filing in January 2024. See t he "Other Matters" section of Item 7 Management's Discussion and Analysis for further details on IRPs. Duke Energy continues to evaluate the retirement date assumptions for coal-fired generating facilities as changes in energy usage and/or growth and availability of replacement generation could result in different retirement dates of units than their current estimated useful lives. Except as discussed above related to Duke Energy Kentucky's East Bend plant, rate cases re cently filed or approved across all jurisdictions included proposed depreciation rates reflecting the 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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