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Regulatory Matters | 12 Months Ended
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Dec. 31, 2022
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) | 2022 |  | 2021 |  | 2022 |  | 2021 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Regulatory Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
AROs – coal ash | $ | 3,205 |  |  | $ | 3,408 |  |  | $ | 1,429 |  |  | $ | 1,399 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
AROs – nuclear and other | 945 |  |  | 684 |  |  | 884 |  |  | 620 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred fuel and purchased power | 3,866 |  |  | 1,253 |  |  | 2,060 |  |  | 718 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Accrued pension and OPEB | 2,336 |  |  | 2,017 |  |  | 759 |  |  | 725 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Storm cost securitized balance, net | 940 |  |  | 991 |  |  | 720 |  |  | 759 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Nuclear asset securitized balance, net | 881 |  |  | 937 |  |  | 881 |  |  | 937 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Debt fair value adjustment | 829 |  |  | 884 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Storm cost deferrals | 666 |  |  | 213 |  |  | 559 |  |  | 189 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Hedge costs deferrals | 378 |  |  | 348 |  |  | 128 |  |  | 137 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Post-in-service carrying costs (PISCC) and deferred operating expenses | 342 |  |  | 356 |  |  | 42 |  |  | 47 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Retired generation facilities | 316 |  |  | 357 |  |  | 243 |  |  | 265 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred asset – Lee and Harris COLA | 288 |  |  | 317 |  |  | 21 |  |  | 21 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Advanced metering infrastructure (AMI) | 283 |  |  | 311 |  |  | 111 |  |  | 130 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Customer connect project | 271 |  |  | 242 |  |  | 136 |  |  | 124 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Costs of removal regulatory asset | 221 |  |  | 107 |  |  | 221 |  |  | 107 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Vacation accrual | 222 |  |  | 221 |  |  | 43 |  |  | 42 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Incremental COVID-19 expenses | 210 |  |  | 87 |  |  | 78 |  |  | 28 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
CEP deferral | 190 |  |  | 161 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Demand side management (DSM)/Energy efficiency (EE) | 189 |  |  | 235 |  |  | 188 |  |  | 230 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Derivatives – natural gas supply contracts | 168 |  |  | 139 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NCEMPA deferrals | 157 |  |  | 165 |  |  | 157 |  |  | 165 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Nuclear deferral | 154 |  |  | 120 |  |  | 64 |  |  | 42 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred pipeline integrity costs | 121 |  |  | 108 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
COR settlement | 120 |  |  | 123 |  |  | 32 |  |  | 32 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred coal ash handling system costs | 92 |  |  | 90 |  |  | 25 |  |  | 23 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Qualifying facility contract buyouts | 81 |  |  | 94 |  |  | 81 |  |  | 94 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Amounts due from customers | 57 |  |  | 85 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Propane caverns | 26 |  |  | — |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred severance charges | 21 |  |  | 54 |  |  | 7 |  |  | 18 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Manufactured gas plant (MGP) | — |  |  | 104 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other | 555 |  |  | 426 |  |  | 110 |  |  | 87 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total regulatory assets | 18,130 |  |  | 14,637 |  |  | 8,979 |  |  | 6,939 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Less: current portion | 3,485 |  |  | 2,150 |  |  | 1,833 |  |  | 1,030 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total noncurrent regulatory assets | $ | 14,645 |  |  | $ | 12,487 |  |  | $ | 7,146 |  |  | $ | 5,909 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Regulatory Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net regulatory liability related to income taxes | $ | 6,462 |  |  | $ | 7,199 |  |  | $ | 2,192 |  |  | $ | 2,394 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Costs of removal | 5,151 |  |  | 6,150 |  |  | 2,269 |  |  | 2,955 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
AROs – nuclear and other | 1,038 |  |  | 2,053 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Hedge cost deferrals | 683 |  |  | 364 |  |  | 252 |  |  | 155 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Accrued pension and OPEB | 211 |  |  | 213 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
DOE Settlement | 154 |  |  | — |  |  | 154 |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Provision for rate refunds | 78 |  |  | 274 |  |  | 28 |  |  | 87 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Amounts to be refunded to customers | 45 |  |  | — |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other | 1,226 |  |  | 1,110 |  |  | 434 |  |  | 453 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total regulatory liabilities | 15,048 |  |  | 17,363 |  |  | 5,329 |  |  | 6,044 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Less: current portion | 1,466 |  |  | 1,211 |  |  | 576 |  |  | 478 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total noncurrent regulatory liabilities | $ | 13,582 |  |  | $ | 16,152 |  |  | $ | 4,753 |  |  | $ | 5,566 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
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. Storm cost deferrals. Represents deferred incremental costs incurred related to major weather-related events. 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. 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. 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. Customer connect project. Represents incremental operating expenses and carrying costs on deferred amounts related to the deployment of the new customer information system. Vacation accrual. Represents vacation entitlement, which is generally recovered in the following year. Incremental COVID-19 expenses. Represents incremental costs related to ensuring continuity and quality of service in a safe manner during the COVID-19 pandemic. CEP deferral. Represents deferred depreciation, PISCC and deferred property tax for Duke Energy Ohio Gas capital assets for the Capital Expenditure Program (CEP). DSM/EE. Deferred costs related to various DSM and EE programs recoverable through various mechanisms. Derivatives – natural gas supply contracts. Represents costs for certain long-dated, fixed quantity forward natural gas supply contracts, which are recoverable through PGA clauses. NCEMPA deferrals. Represents retail allocated cost deferrals and returns associated with the additional ownership interest in assets acquired from NCEMPA in 2015. Nuclear deferral. Includes amounts related to levelizing nuclear plant outage costs, which allows for the recognition of nuclear outage expenses over the refueling cycle rather than when the outage occurs, resulting in the deferral of operations and maintenance costs associated with refueling. Deferred pipeline integrity costs. Represents pipeline integrity management costs in compliance with federal regulations. COR settlement. Represents approved COR settlements that are being amortized over the average remaining lives, at the time of approval, of the associated assets. 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. Amounts due from customers. Relates primarily to margin decoupling and IMR recovery mechanisms. Costs of removal 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. Propane Caverns. Represents amounts for costs related to propane inventory, the net book value of remaining assets and decommissioning costs at Duke Energy Ohio. MGP. Represents remediation costs incurred at former MGP sites and the deferral of costs to be incurred at Duke Energy Ohio's East End and West End sites. 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. Costs of removal. 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, 2022. 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, 2022. 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 territories in North Carolina and South Carolina. Approximately 950,000 customers were impacted. Total estimated operation and maintenance expenses incurred for restoration efforts for the year ended December 31, 2022, were approximately $100 million, with an additional $9 million in capital investments. Approximately $83 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, 2022 ($40 million and $43 million for Duke Energy Carolinas and Duke Energy Progress, respectively). Duke Energy Carolinas and Duke Energy Progress 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. Car bon Plan Proceeding On October 13, 2021, North Carolina enacted legislation (Energy Solutions for North Carolina or HB 951) that established a framework overseen by the NCUC to advance North Carolina CO 2 emission reductions from electric generating facilities in the state through the use of least cost planning while providing for continued reliability and affordable rates for customers. Among other things, HB 951 directed that the NCUC approve an initial carbon plan (Carbon Plan) by December 31, 2022, taking all reasonable steps to achieve a 70% reduction in CO 2 emissions from public utilities’ electric generating facilities in the state by 2030 (from 2005 levels) and achieve carbon neutrality from electric generating facilities by 2050 while maintaining affordability and reliability for customers. On May 16, 2022, Duke Energy Carolinas and Duke Energy Progress filed their proposed Carolinas Carbon Plan (Proposed Plan) with the NCUC. The NCUC issued an order on December 30, 2022, adopting the first Carbon Plan. The order recognizes the value of an “all-of-the-above” approach to achieving CO 2 emission reductions and established a set of near-term procurement and development activities needed to continue progress towards the targeted CO 2 reductions, along with the schedule for the future biennial updates to the Carbon Plan. The approved near-term action plan includes procurement and development of solar, storage and hydrogen-capable natural gas generation at levels consistent with the Proposed Plan, along with upgrading key transmission facilities to strengthen the grid, improve resilience for customers and interconnect new solar generation and stakeholder engagement activities for onshore wind generation (in all cases, subject to any further applicable regulatory processes). The order also approved early development activities for long lead-time resources, including new nuclear, pumped-hydro storage and offshore wind transmission development. The NCUC affirmed the utility ownership structure required in HB 951; all new generation facilities or other resources selected by the NCUC to achieve the CO 2 emission reductions shall be owned and recovered on a cost-of-service basis by the utilities, with a carveout for 45% of solar and solar plus storage generation to be procured through long-term purchase power agreements with third parties. The order approves continued utilization of the remaining coal-fired generation assets, ensuring that appropriate replacement generating units and associated transmission infrastructure are in service before existing generating units are retired and providing an orderly transition out of coal generation by 2035. Storm Cost Securitization Legislation On June 15, 2022, the South Carolina General Assembly unanimously adopted S. 1077 (Act 227) in both the House and Senate and the bill was signed into law on June 17, 2022. The legislation enables the PSCSC to permit the issuance of bonds for the payment of storm costs and the creation of a storm charge for repayment. On August 5, 2022, Duke Energy Progress filed a petition with the PSCSC for review and approval of deferred storm costs to be securitized of approximately $223 million. The evidentiary hearing is scheduled to begin on or after March 1, 2023. On February 7, 2023, a stipulation was reached with all parties in the proceeding regarding certain items identified through the Office of Regulatory Staff (ORS) audit of storm costs. The final amount for securitization will depend on the outcome of the hearing. Duke Energy Progress cannot predict the outcome of this matter. 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) | 2022 | 2021 |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
AROs – coal ash | $ | 1,391 |  | $ | 1,227 |  |  | (g) | (b)
Deferred fuel and purchased power(i) | 1,614 |  | 339 |  |  | (e) | 2024
Accrued pension and OPEB(c) | 614 |  | 365 |  |  | Yes | (h)
Storm cost securitized balance, net | 220 |  | 232 |  |  |  | 2041
Storm cost deferrals | 93 |  | 22 |  |  | Yes | (b)
Hedge costs deferrals(c) | 228 |  | 171 |  |  | Yes | (b)
PISCC and deferred operating expenses(c) | 30 |  | 31 |  |  | Yes | (b)
Retired generation facilities(c) | 39 |  | 54 |  |  | Yes | (b)
Deferred asset – Lee COLA | 267 |  | 296 |  |  |  | (b)
AMI | 139 |  | 140 |  |  | Yes | (b)
Customer connect project | 62 |  | 66 |  |  | Yes | (b)
Vacation accrual | 84 |  | 83 |  |  |  | 2023
Incremental COVID-19 expenses | 127 |  | 51 |  |  | Yes | (b)
Nuclear deferral | 90 |  | 78 |  |  |  | 2024
COR settlement | 88 |  | 91 |  |  | Yes | (b)
Deferred coal ash handling system costs | 67 |  | 67 |  |  | Yes | (b)
Other | 235 |  | 166 |  |  |  | (b)
Total regulatory assets | 5,388 |  | 3,479 |  |  |  |
Less: current portion | 1,095 |  | 544 |  |  |  |
Total noncurrent regulatory assets | $ | 4,293 |  | $ | 2,935 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
Net regulatory liability related to income taxes(d) | $ | 2,475 |  | $ | 2,785 |  |  |  | (b)
Costs of removal(c) | 1,769 |  | 2,009 |  |  | Yes | (f)
AROs – nuclear and other | 1,038 |  | 2,053 |  |  |  | (b)
Hedge cost deferrals | 350 |  | 209 |  |  |  | (b)
Accrued pension and OPEB(c) | 44 |  | 44 |  |  | Yes | (h)
Provision for rate refunds | 50 |  | 124 |  |  | Yes | (b)
Other | 587 |  | 461 |  |  |  | (b)
Total regulatory liabilities | 6,313 |  | 7,685 |  |  |  |
Less: current portion | 530 |  | 487 |  |  |  |
Total noncurrent regulatory liabilities | $ | 5,783 |  | $ | 7,198 |  |  |  |
(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, both discussed in Note 24. 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. (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 May 2022 for recovery of $327 million, which included deferrals through January 2022. This amount is expected to be recovered through August 2023. The next filing will be made in the first quarter of 2023. Duke Energy Carolinas submitted a fuel filing to the PSCSC in July 2022 for recovery of $79 million, which included deferrals through May 2022. The amount is expected to be recovered through September 2023. The next filing will be made in the third quarter of 2023. 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 includes an MYRP to recover projected capital investments during the three year MYRP period. In addition to the MYRP, the PBR Application includes an Earnings Sharing Mechanism, Residential Decoupling Mechanism and Performance Incentive Mechanisms as required by HB 951. If approved, the overall retail revenue increase would be $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 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 included in the MYRP consistent with the Carbon Plan. Duke Energy Carolinas plans to implement temporary rates, subject to refund, on September 1, 2023, and has requested permanent rates be effective by January 1, 2024. Duke Energy Carolinas cannot predict the outcome of this matter. Oconee Nuclear Station Subsequent License Renewal On June 7, 2021, Duke Energy Carolinas filed a subsequent license renewal (SLR) application for the Oconee Nuclear Station (ONS) with the U.S. Nuclear Regulatory Commission (NRC) to renew ONS’s operating license for an additional 20 years. The SLR would extend operations of the facility from 60 to 80 years. The current licenses for units 1 and 2 expire in 2033 and the license for unit 3 expires in 2034. By a Federal Register Notice dated July 28, 2021, the NRC provided a 60-day comment period for persons whose interest may be affected by the issuance of a subsequent renewed license for ONS to file a request for a hearing and a petition for leave to intervene. On September 27, 2021, Beyond Nuclear and Sierra Club (Petitioners) filed a Hearing Request and Petition to Intervene (Hearing Request) and a Petition for Waiver. The Hearing Request proposed three contentions and claimed that Duke Energy Carolinas did not satisfy the National Environmental Policy Act (NEPA) of 1969, as amended, or the NRC’s NEPA-implementing regulations. Following Duke Energy Carolinas' answer and the Petitioners' reply, on February 11, 2022, the Atomic Safety and Licensing Board (ASLB) issued its decision on the Hearing Request and found that the Petitioners failed to establish that the proposed contentions are litigable. The ASLB also denied the Petitioners' Petition for Waiver and terminated the proceeding. On February 24, 2022, the NRC issued a decision in the SLR appeal related to Florida Power and Light's Turkey Point nuclear generating station in Florida. The NRC ruled that the NRC’s license renewal Generic Environmental Impact Statement (GEIS) does not apply to SLR because the GEIS does not address SLR. The decision overturned a 2020 NRC decision that found the GEIS applies to SLR. Although Turkey Point is not owned or operated by a Duke Energy Registrant, the NRC’s order applies to all SLR applicants, including ONS. The NRC order also indicated no subsequent renewed licenses will be issued until the NRC staff has completed an adequate NEPA review for each application. On April 5, 2022, the NRC approved a 24-month rulemaking plan that will enable the NRC staff to complete an adequate NEPA review. Although an SLR applicant may wait until the rulemaking is completed, the NRC also noted that an applicant may submit a supplement to its environmental report providing information on environmental impacts during the SLR period prior to the rulemaking being completed. On November 7, 2022, Duke Energy Carolinas submitted a supplement to its environmental report addressing environmental impacts during the SLR period. On December 19, 2022, the NRC published a notice in the Federal Register that the NRC will conduct a limited scoping process to gather additional information necessary to prepare an environmental impact statement (EIS) to evaluate the environmental impacts at ONS during the SLR period. The NRC received comments from the EPA and the Petitioners and these comments identify eighteen potential impacts that should be considered by the NRC in the EIS, which include, but are not limited to, climate change and flooding, environmental justice, severe accidents, and external events. Currently, the NRC expects to publish a draft EIS in October 2023. On December 19, 2022, the NRC issued the Safety Evaluation Report (SER) for the safety portion of the SLR application. The NRC determined Duke Energy Carolinas met the requirements of the applicable regulations and identified actions that have been taken or will be taken to manage the effects of aging and address time-limited analyses. Duke Energy Carolinas and the NRC met with the Advisory Committee on Reactor Safeguards (ACR S) on February 2, 2023, to discuss issues regarding the SER and SLR application, after which the ACRS will issue a report discussing the result of its review. Although the NRC’s GEIS applicability decision will delay completion of the SLR proceeding, Duke Energy Carolinas does not believe it changes the probability that the ONS subsequent renewed licenses will ultimately be issued, although Duke Energy Carolinas cannot guarantee the outcome of the license application process. Duke Energy Carolinas and Duke Energy Progress intend to seek renewal of operating licenses and 20-year license extensions for all of their nuclear stations. New depreciation rates were implemented for all of the nuclear facilities during the second quarter of 2021. Duke Energy Carolinas and Duke Energy Progress cannot predict the outcome of these additional relicensing proceedings. 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) | 2022 | 2021 |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
AROs – coal ash | $ | 1,418 |  | $ | 1,389 |  |  | (g) | (b)
AROs – nuclear and other | 869 |  | 613 |  |  |  | (c)
Deferred fuel and purchased power(l) | 705 |  | 303 |  |  | (e) | 2024
Accrued pension and OPEB(d) | 417 |  | 351 |  |  | Yes | (j)
Storm cost securitized balance, net | 720 |  | 759 |  |  |  | 2041
Storm cost deferrals | 234 |  | 170 |  |  | Yes | (b)
Hedge costs deferrals | 55 |  | 60 |  |  |  | (b)
PISCC and deferred operating expenses | 42 |  | 47 |  |  | Yes | 2054
Retired generation facilities | 149 |  | 171 |  |  | Yes | (b)
Deferred asset - Harris COLA | 21 |  | 21 |  |  |  | (b)
AMI | 81 |  | 92 |  |  | Yes | (b)
Customer connect project | 54 |  | 57 |  |  | Yes | (b)
Vacation accrual | 43 |  | 42 |  |  |  | 2023
Incremental COVID-19 expenses | 78 |  | 28 |  |  | Yes | (b)
DSM/EE(d) | 180 |  | 218 |  |  | (h) | (h)
NCEMPA deferrals | 157 |  | 165 |  |  | (f) | 2042
Nuclear deferral | 64 |  | 42 |  |  |  | 2024
COR settlement | 32 |  | 32 |  |  | Yes | (b)
Deferred coal ash handling system costs | 25 |  | 23 |  |  | Yes | (b)
Other | 70 |  | 68 |  |  |  | (b)
Total regulatory assets | 5,414 |  | 4,651 |  |  |  |
Less: current portion | 690 |  | 533 |  |  |  |
Total noncurrent regulatory assets | $ | 4,724 |  | $ | 4,118 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
Net regulatory liability related to income taxes(k) | $ | 1,559 |  | $ | 1,695 |  |  |  | (b)
Costs of removal(d) | 2,269 |  | 2,955 |  |  | Yes | (i)
Hedge cost deferrals | 252 |  | 155 |  |  |  | (b)
Provision for rate refunds | 28 |  | 87 |  |  | Yes | (b)
Other | 344 |  | 357 |  |  |  | (b)
Total regulatory liabilities | 4,452 |  | 5,249 |  |  |  |
Less: current portion | 332 |  | 381 |  |  |  |
Total noncurrent regulatory liabilities | $ | 4,120 |  | $ | 4,868 |  |  |  |
(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. (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, both discussed in Note 24. Portions are included in rate base. (l) Duke Energy Progress submitted a fuel filing to the NCUC in August 2022 for recovery of $251 million, which included deferrals through June 2022. This amount is expected to be recovered through November 2023. The next filing will be made in the second quarter of 2023. Duke Energy Progress submitted a fuel filing to the PSCSC in April 2022 for recovery of $44 million, which included deferrals through February 2022. This amount is expected to be recovered through June 2023. The next filing will be made in the second quarter of 2023. 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 includes an MYRP to recover projected capital investments during the three year MYRP period. In addition to the MYRP, the PBR Application includes an Earnings Sharing Mechanism, Residential Decoupling Mechanism and Performance Incentive Mechanisms as required by HB 951. If approved, the overall retail revenue increase would be $326 million in Year 1, $151 million in Year 2 and $138 million in Year 3, for a combined total of $615 million or 16% by late 2025. 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 included in the MYRP consistent with the Carbon Plan. Duke Energy Progress plans to implement temporary rates, subject to refund, on June 1, 2023, and has requested permanent rates be effective by October 1, 2023. The evidentiary hearing has been scheduled to begin on May 1, 2023. 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. The PSCSC voted to allow Duke Energy Progress to implement new customer rates by April 1, 2023. A final written order is due from the PSCSC by March 1, 2023. FERC Return on Equity Complaint On October 16, 2020, North Carolina Electric Membership Corporation (NCEMC) filed a complaint at the FERC against Duke Energy Progress pursuant to Section 206 of the Federal Power Act (FPA), alleging that the 11% stated ROE component in the demand formula rate in the Power Supply and Coordination Agreement between NCEMC and Duke Energy Progress is unjust and unreasonable. On June 16, 2022, Duke Energy Progress submitted to the FERC an Offer of Settlement and Settlement Agreement (Settlement Agreement) between NCEMC and Duke Energy Progress. The Settlement Agreement provides for an ROE of 10%, effective January 1, 2022, among other contract modifications. On November 7, 2022, the FERC approved the Settlement Agreement. 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) | 2022 | 2021 |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
AROs – coal ash | $ | 11 |  | $ | 10 |  |  |  | (b)
AROs – nuclear and other | 15 |  | 7 |  |  |  | (b)
Deferred fuel and purchased power(h) | 1,355 |  | 415 |  |  | (f) | 2024
Accrued pension and OPEB(c) | 342 |  | 374 |  |  | Yes | (g)
Nuclear asset securitized balance, net | 881 |  | 937 |  |  |  | 2036
Storm cost deferrals(c) | 325 |  | 19 |  |  | (f) | (b)
Hedge costs deferrals(c) | 73 |  | 77 |  |  | Yes | 2038
Retired generation facilities(c) | 94 |  | 94 |  |  | Yes | 2044
AMI(c) | 30 |  | 38 |  |  | Yes | 2032
Customer connect project(c) | 82 |  | 67 |  |  | Yes | 2037
Costs of removal regulatory asset(c) | 221 |  | 107 |  |  | (d) | (b)
Qualifying facility contract buyouts(c) | 81 |  | 94 |  |  | Yes | 2034
Other | 55 |  | 49 |  |  | (d) | (b)
Total regulatory assets | 3,565 |  | 2,288 |  |  |  |
Less: current portion | 1,143 |  | 497 |  |  |  |
Total noncurrent regulatory assets | $ | 2,422 |  | $ | 1,791 |  |  |  |
Net regulatory liability related to income taxes(c) | $ | 633 |  | $ | 699 |  |  |  | (b)
DOE Settlement | 154 |  | — |  |  |  |
Other | 90 |  | 97 |  |  | (d) | (b)
Total regulatory liabilities | 877 |  | 796 |  |  |  |
Less: current portion | 244 |  | 98 |  |  |  |
Total noncurrent regulatory liabilities | $ | 633 |  | $ | 698 |  |  |  |
(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 a debt return/interest once collections begin. (f) Earns commercial paper rate. (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) Duke Energy Florida submitted a fuel filing to the FPSC in January 2023 for recovery of $795 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 expected recovery period is April 2023 through March 2024. 2021 Settlement Agreement On January 14, 2021, Duke Energy Florida filed a Settlement Agreement (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 Agreement also provided that Duke Energy Florida will be able to retain the $173 million retail portion 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. The full amount of the $173 million is expected to be recognized between the years of 2023 and 2024, while also remaining within the approved ROE band. 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. 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. The program consists 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 the oral argument 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. 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 Office of Public Counsel filed a notice of appeal of this order to the Florida Supreme Court. Duke Energy Florida cannot predict the outcome of this matter. Hurricane Ian 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 December 31, 2022 Consolidated Balance Sheets include an estimate of approximately $353 million 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. Duke Energy Florida cannot predict the outcome of this matter. 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) | 2022 | 2021 |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
AROs – coal ash | $ | — |  | $ | 33 |  |  | Yes | (b)
Deferred fuel and purchased power | 54 |  | 38 |  |  |  | 2023
Accrued pension and OPEB | 129 |  | 133 |  |  |  | (e)
Storm cost deferrals | 14 |  | 2 |  |  |  | 2023
Hedge costs deferrals | 2 |  | 5 |  |  |  | (b)
PISCC and deferred operating expenses(c) | 15 |  | 16 |  |  | Yes | 2083
AMI | 18 |  | 24 |  |  |  | (b)
Customer connect project | 54 |  | 41 |  |  |  | (b)
CEP deferral | 190 |  | 161 |  |  | Yes | (b)
Deferred pipeline integrity costs | 28 |  | 24 |  |  | Yes | (b)
Propane caverns | 26 |  | — |  |  |  | (b)
Manufactured gas plant (MGP) | — |  | 104 |  |  |  | (b)
Other | 154 |  | 126 |  |  |  | (b)
Total regulatory assets | 684 |  | 707 |  |  |  |
Less: current portion | 103 |  | 72 |  |  |  |
Total noncurrent regulatory assets | $ | 581 |  | $ | 635 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
Net regulatory liability related to income taxes | $ | 496 |  | $ | 602 |  |  |  | (b)
Costs of removal | 9 |  | 39 |  |  |  | (d)
Accrued pension and OPEB | 21 |  | 21 |  |  |  | (e)
Provision for rate refunds | — |  | 61 |  |  |  |
Other | 107 |  | 78 |  |  |  | (b)
Total regulatory liabilities | 633 |  | 801 |  |  |  |
Less: current portion | 99 |  | 62 |  |  |  |
Total noncurrent regulatory liabilities | $ | 534 |  | $ | 739 |  |  |  |
(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 and an ROE of 10.3%. This is an approximate 3.3% average increase in the customer's total bill across all customer classes. The drivers for this case are capital invested since Duke Energy Ohio's last electric distribution base rate case in 2017. Duke Energy Ohio is also seeking to adjust the caps on its Distribution Capital Investment Rider (DCI Rider). The Staff of the PUCO (Staff) report was issued on May 19, 2022, recommending an increase in electric distribution base rates of $2 million to $15 million with an ROE range of 8.84% to 9.85%. On September 19, 2022, Duke Energy Ohio filed a Stipulation and Recommendation with the PUCO, which includes an increase in overall electric distribution base rates of approximately $23 million and an ROE of 9.5%. The stipulation is among all but one party to the proceeding. The PUCO issued an order on December 14, 2022, approving the Stipulation without material modification. Rates went into effect on January 3, 2023. The Ohio Consumers' Counsel (OCC) filed an application for rehearing on January 13, 2023. 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. Duke Energy Ohio took the following actions: •On March 27, 2020, Duke Energy Ohio filed an application for rehearing seeking clarification on the final true up and reconciliation process after 2020. On November 18, 2020, the PUCO issued an order replacing the cost cap previously imposed upon Duke Energy Ohio with a cap on shared savings recovery. On December 18, 2020, Duke Energy Ohio filed an additional application for rehearing challenging, among other things, the imposition of the cap on shared savings. On January 13, 2021, the application for rehearing was granted for further consideration. •On October 9, 2020, Duke Energy Ohio filed an application to implement a voluntary energy efficiency program portfolio to commence on January 1, 2021. The application proposed a mechanism for recovery of program costs and a benefit associated with avoided transmission and distribution costs. This application remains under review. •On November 18, 2020, the PUCO issued an order directing all utilities to set their energy efficiency riders to zero effective January 1, 2021, and to file a separate application for final reconciliation of all energy efficiency costs prior to December 31, 2020. Effective January 1, 2021, Duke Energy Ohio suspended its energy efficiency programs. •On June 14, 2021, the PUCO requested each utility to file by July 15, 2021, a proposal to reestablish low-income programs through December 31, 2021. Duke Energy Ohio filed its application on July 14, 2021. •On February 23, 2022, the PUCO issued its Fifth Entry on Rehearing that 1) affirmed its reduction in Duke Energy Ohio's shared savings cap; 2) denied rehearing/clarification regarding lost distribution revenues and shared savings recovery for periods after December 31, 2020; and 3) directed Duke Energy Ohio to submit an updated application with exhibits. •On March 25, 2022, Duke Energy Ohio filed its Amended Application consistent with the PUCO's order. Duke Energy Ohio cannot predict the outcome of this matter. 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 and an ROE of 10.3%. This is an approximate 5.6% average increase in the customer's total bill across all customer classes. The drivers for this case are capital invested since Duke Energy Ohio's last natural gas base rate case in 2012. Duke Energy Ohio is also seeking to adjust the caps on its Capital Expenditure Program Rider (CEP Rider). The Staff of the PUCO (Staff) report was issued on December 21, 2022, recommending an increase in natural gas base rates of $24 million to $36 million, with an equity ratio of 52% and an ROE range of 9.03% to 10.04%. A procedural schedule was issued on December 22, 2022, scheduling the evidentiary hearing to commence on March 28, 2023. Duke Energy Ohio cannot predict the outcome of this matter. Natural Gas Pipeline Extension Duke Energy Ohio installed a new natural gas pipeline (the Central Corridor Project) in its Ohio service territory to increase system reliability and enable the retirement of older infrastructure. Construction of the pipeline extension was completed and placed in service on March 14, 2022, with a total cost of approximately $170 million (excluding overheads and AFUDC). 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 new rider to implement the benefits of the Tax Act for natural gas customers. The new 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, resolves 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 subject to normalization rules will be refunded consistent with federal law through a new rider. Deferred income taxes not sub ject to normalization rules were written off. 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 and an ROE of 10.35%. This is an overall increase in rates of approximately 17.8%. The request for rate increase is 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 is also requesting new programs and tariff updates, including a voluntary community-based renewable subscription program and two EV charging programs. A procedural schedule was issued on December 19, 2022, scheduling the evidentiary hearing for May 9, 2023. New rates are anticipated to go into effect around July 15, 2023. 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) | 2022 | 2021 |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
AROs – coal ash | $ | 385 |  | $ | 749 |  |  | Yes | (b)
Deferred fuel and purchased power | 138 |  | 158 |  |  |  | 2023
Accrued pension and OPEB | 214 |  | 222 |  |  |  | (e)
Hedge costs deferrals | 20 |  | 35 |  |  |  | (b)
PISCC and deferred operating expenses(c) | 255 |  | 262 |  |  | Yes | (b)
Retired generation facilities(c) | 34 |  | 38 |  |  | Yes | 2030
AMI | 15 |  | 17 |  |  |  | 2031
Customer connect project | 19 |  | 11 |  |  |  | (b)
Other | 44 |  | 63 |  |  |  | (b)
Total regulatory assets | 1,124 |  | 1,555 |  |  |  |
Less: current portion | 249 |  | 277 |  |  |  |
Total noncurrent regulatory assets | $ | 875 |  | $ | 1,278 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
Net regulatory liability related to income taxes | $ | 840 |  | $ | 908 |  |  |  | (b)
Costs of removal | 531 |  | 575 |  |  |  | (d)
Hedge cost deferrals | 81 |  | — |  |  |  | (b)
Accrued pension and OPEB | 104 |  | 113 |  |  |  | (e)
Other | 85 |  | 96 |  |  |  | (b)
Total regulatory liabilities | 1,641 |  | 1,692 |  |  |  |
Less: current portion | 187 |  | 127 |  |  |  |
Total noncurrent regulatory liabilities | $ | 1,454 |  | $ | 1,565 |  |  |  |
(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. Approximately 50% of the reduction was due to a prospective change in depreciation and use of regulatory asset for the end-of-life inventory at retired generating plants, approximately 20% was due to the approved ROE of 9.7% versus the requested ROE of 10.4% and approximately 20% was related to miscellaneous earnings neutral adjustments. Step one rates were estimated to be approximately 75% of the total 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 has been 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. An evidentiary hearing is scheduled to begin March 3, 2023. Duke Energy Indiana cannot predict the outcome of this matter. 2020 Indiana Coal Ash Recovery Case 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 the Indiana Department of Environmental Management (IDEM) as well as continuing deferral, with carrying costs, on the balance. An evidentiary hearing was held on September 14, 2020. Briefing was completed by mid-September 2021. 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. Duke Energy Indiana is assessing its appellate options and must file a petition to transfer to the Indiana Supreme Court by April 7, 2023. As a result of the court's 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. 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 the 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. 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) | 2022 | 2021 |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
AROs – nuclear and other | $ | 27 |  | $ | 22 |  |  |  | (d)
Accrued pension and OPEB(c) | 119 |  | 82 |  |  |  | (g)
Vacation accrual | 12 |  | 12 |  |  |  | 2023
Derivatives – natural gas supply contracts(f) | 168 |  | 139 |  |  |  |
Deferred pipeline integrity costs(c) | 93 |  | 84 |  |  |  | 2025
Amounts due from customers | 57 |  | 85 |  |  | (e) | (b)
Other | 35 |  | 33 |  |  |  | (b)
Total regulatory assets | 511 |  | 457 |  |  |  |
Less: current portion | 119 |  | 141 |  |  |  |
Total noncurrent regulatory assets | $ | 392 |  | $ | 316 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
Net regulatory liability related to income taxes | $ | 459 |  | $ | 510 |  |  |  | (b)
Costs of removal(c) | 573 |  | 572 |  |  |  | (d)
Other | 66 |  | 32 |  |  | (e) | (b)
Total regulatory liabilities | 1,098 |  | 1,114 |  |  |  |
Less: current portion | 74 |  | 56 |  |  |  |
Total noncurrent regulatory liabilities | $ | 1,024 |  | $ | 1,058 |  |  |  |
(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. 2022 South Carolina Rate Case On April 1, 2022, Piedmont filed an application with the PSCSC for a rate increase for retail customers of approximately $7 million, which represents an approximate 3.4% increase in retail revenues. An evidentiary hearing was held on August 15, 2022. On September 15, 2022, the PSCSC delivered its decision, which included an ROE of 9.3% and a capital structure of 52.2% equity and 47.8% debt and issued its final order on October 6, 2022. Revised customer rates became effective in October 2022 and resulted in a rate decrease for retail customers of approximately $1 million. Tennessee Annual Review Mechanism On October 10, 2022, the TPUC approved Piedmont’s petition to adopt an Annual Review Mechanism (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 is 2022, and the initial rate adjustments request will be filed in May 2023 for rates effective October 1, 2023. OTHER REGULATORY MATTERS Atlantic Coast Pipeline, LLC Atlantic Coast Pipeline (ACP pipeline) was planned to be an approximately 600-mile interstate natural gas pipeline running from West Virginia to North Carolina. Duke Energy indirectly owns a 47% interest, which is accounted for as an equity method investment through its Gas Utilities and Infrastructure segment. As a result of the uncertainty created by various legal rulings, the potential impact on the cost and schedule for the project, the ongoing legal challenges and the risk of additional legal challenges and delays through the construction period and Dominion’s decision to sell substantially all of its gas transmission and storage segment assets, Duke Energy's Board of Directors and management decided that it was not prudent to continue to invest in the project. On July 5, 2020, Duke Energy and Dominion announced the cancellation of the ACP pipeline project. As part of the pretax charges to earnings of approximately $2.1 billion recorded for the year ended December 31, 2020, within Equity in earnings (losses) of unconsolidated affiliates on the Duke Energy Consolidated Statements of Operations, Duke Energy established liabilities related to the cancellation o f the ACP pipeline project. In February 2021, Duke Energy paid approximately $855 million to fund ACP's outstanding debt, relieving Duke Energy of its guarantee. At December 31, 2022, there is $59 million and $47 million within Other Current Liabilities and Other Noncurrent Liabilities, respectively, in the Gas Utilities and Infrastructure segment. The liabilities represent Duke Energy's obligation of approximately $106 million to satisfy remaining ARO requirements to restore construction sites. See Notes 8 and 13 for add itional information regarding this transaction. 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 options being considered to meet those needs. IRPs filed by the Subsidiary Registrants included planning assumptions to potentially retire certain coal-fired generating facilities in North Carolina and Indiana earlier than their current estimated useful l ives. The NCUC concluded in its Carbon Plan order that the projected retirements 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 continues to evaluate the potential need to retire these coal-fired generating facilities earlier than the current estimated useful lives and plans to seek regulatory recovery for amounts that would not be otherwise recovered when any of these assets are retired. The table below contains the net carrying value of generating facilities planned for retirement or included in recent IRPs or Carbon Plan as evaluated for potential retirement. Dollar amounts in the table below are included in Net property, plant and equipment on the Consolidated Balance Sheets as of December 31, 2022, and exclude capitalized asset retirement costs.
|  |  |  |  |  |  |  |  | Remaining Net |  |  |  |
| Capacity |  |  |  |  |  |  |  | Book Value |  |  |  |
| (in MW) |  |  |  |  |  |  |  | (in millions) |  |  |  |
Duke Energy Carolinas |  |  |  |  |  |  |  |  |  |  |  |  |
Allen Steam Station Unit 1(a) | 167 |  |  |  |  |  |  |  |  | $ | 10 |  |  |  |  |
Allen Steam Station Unit 5(b) | 259 |  |  |  |  |  |  |  |  | 233 |  |  |  |  |
Cliffside Unit 5(b) | 546 |  |  |  |  |  |  |  |  | 344 |  |  |  |  |
Marshall Units 1-2(b) | 760 |  |  |  |  |  |  |  | 428 |  |  |  |
Duke Energy Progress |  |  |  |  |  |  |  |  |  |  |  |  |
Mayo Unit 1(b) | 713 |  |  |  |  |  |  |  |  | 639 |  |  |  |  |
Roxboro Units 3-4(b) | 1,409 |  |  |  |  |  |  |  |  | 425 |  |  |  |  |
Duke Energy Florida |  |  |  |  |  |  |  |  |  |  |  |  |
Crystal River Units 4-5(c) | 1,442 |  |  |  |  |  |  |  |  | 1,549 |  |  |  |  |
Duke Energy Indiana |  |  |  |  |  |  |  |  |  |  |  |  |
Gibson Units 1-5(d) | 2,845 |  |  |  |  |  |  |  |  | 2,043 |  |  |  |  |
Cayuga Units 1-2(d) | 1,005 |  |  |  |  |  |  |  |  | 622 |  |  |  |  |
Total Duke Energy | 9,146 |  |  |  |  |  |  |  |  | $ | 6,293 |  |  |  |  |
(a) As part of the 2015 resolution of a lawsuit involving alleged New Source Review violations, Duke Energy Carolinas must retire Allen Steam Station Unit 1 by December 31, 2024. (b) These units were included in the IRP filed by Duke Energy Carolinas and Duke Energy Progress in South Carolina on September 1, 2020, and in the Carbon Plan adopted by the NCUC in December 2022. The long-term energy options considered could result in retirement of these units earlier than their current estimated useful lives. (c) On January 14, 2021, Duke En ergy Florida filed the 2021 Settlement agreement with the FPSC, which proposed depreciation rates reflecting retirement dates for Duke Energy Florida's last two coal-fired generating facilities, Crystal River Units 4-5, eight years ahead of schedule in 2034 rather than in 2042. The FPSC approved the 2021 Settlement on May 4, 2021. The remaining net book value reflected in the table above excludes $200 million of accelerated deprecation collected from retail customers pursuant to Duke Energy Florida's 2017 Settlement. (d) The rate case filed July 2, 2019, included proposed depreciation rates reflecting retirement dates from 2026 to 2038. The depreciation rates reflecting these updated retirement dates were approved by the IURC as part of the rate case order issued on June 29, 2020.

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