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Regulatory Matters
 12 Months Ended
Dec. 31, 2021
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 EnergyProgress Energy
December 31,December 31,
(in millions)2021202020212020
Regulatory Assets
AROs – coal ash$3,408 $3,408 $1,399 $1,357 
AROs – nuclear and other684 754 620 685 
Accrued pension and OPEB2,017 2,317 725 875 
Deferred fuel and purchased power1,253 213 718 162 
Storm cost securitized balance, net991 — 759 — 
Nuclear asset securitized balance, net937 991 937 991 
Debt fair value adjustment884 950 — — 
Retired generation facilities357 417 265 363 
Post-in-service carrying costs (PISCC) and deferred operating expenses356 397 47 51 
Hedge costs deferrals348 351 137 148 
Deferred asset – Lee and Harris COLA317 356 21 32 
Advanced metering infrastructure (AMI)311 311 130 102 
Customer connect project242 136 124 55 
Demand side management (DSM)/Energy efficiency (EE)235 242 230 241 
Vacation accrual221 221 42 42 
Storm cost deferrals213 1,102 189 893 
NCEMPA deferrals165 124 165 124 
CEP deferral161 117 — — 
Derivatives – natural gas supply contracts139 122 — — 
COR settlement123 128 32 33 
Nuclear deferral120 123 42 35 
Deferred pipeline integrity costs108 92 — — 
Costs of removal regulatory asset107 — 107 — 
Manufactured gas plant (MGP)104 104 — — 
Qualifying facility contract buyouts94 107 94 107 
ABSAT, coal ash basin closure90 98 23 27 
Incremental COVID-19 expenses87 76 28 23 
Amounts due from customers85 110 — — 
Deferred severance charges54 86 18 29 
Other426 609 87 158 
Total regulatory assets14,637 14,062 6,939 6,533 
Less: current portion2,150 1,641 1,030 758 
Total noncurrent regulatory assets$12,487 $12,421 $5,909 $5,775 
Regulatory Liabilities
Net regulatory liability related to income taxes$7,199 $7,368 $2,394 $2,411 
Costs of removal6,150 5,883 2,955 2,666 
AROs – nuclear and other2,053 1,512 — — 
Provision for rate refunds274 344 87 123 
Hedge cost deferrals271 24 117 8 
Accrued pension and OPEB213 177 — — 
Other1,203 1,098 491 483 
Total regulatory liabilities 17,363 16,406 6,044 5,691 
Less: current portion 1,211 1,377 478 640 
Total noncurrent regulatory liabilities $16,152 $15,029 $5,566 $5,051 
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 9 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 9 for additional information.
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 22 for additional detail.
Deferred fuel and purchased power. Represents certain energy-related costs that are recoverable or refundable as approved by the applicable regulatory body.
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.
Retired generation facilities. Represents amounts to be recovered for facilities that have been retired and are probable of recovery.
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.
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.
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.
DSM/EE. Deferred costs related to various DSM and EE programs recoverable through various mechanisms.
Vacation accrual. Represents vacation entitlement, which is generally recovered in the following year.
Storm cost deferrals. Represents deferred incremental costs incurred related to major weather-related events.
NCEMPA deferrals. Represents retail allocated cost deferrals and returns associated with the additional ownership interest in assets acquired from NCEMPA in 2015.
CEP deferral. Represents deferred depreciation, PISCC and deferred property tax for Duke Energy Ohio Gas capital assets for the Capital Expenditure Program (CEP).
Derivatives – natural gas supply contracts. Represents costs for certain long-dated, fixed quantity forward natural gas supply contracts, which are recoverable through PGA clauses.
COR settlement. Represents approved COR settlements that are being amortized over the average remaining lives, at the time of approval, of the associated assets.
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.
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.
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.
Qualifying facility contract buyouts. Represents termination payments for regulatory recovery through the capacity clause.
ABSAT, coal ash basin closure. Represents deferred depreciation and returns associated with Ash Basin Strategic Action Team (ABSAT) capital assets related to converting the ash handling system from wet to dry.
Incremental COVID-19 expenses. Represents incremental costs related to ensuring continuity and quality of service in a safe manner during the COVID-19 pandemic.
Amounts due from customers. Relates primarily to margin decoupling and IMR recovery mechanisms.
Deferred severance charges. Represents costs incurred for employees separation from Duke Energy.
Net regulatory liability related to income taxes. Amounts for all registrants include regulatory liabilities related primarily to impacts from the Tax Act. See Note 23 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.
Provision for rate refunds. Represents estimated amounts due to customers based on recording interim rates subject to refund.
Amounts to be refunded to customers. Represents required rate reductions to retail customers by the applicable regulatory body.
RESTRICTIONS ON THE ABILITY OF CERTAIN SUBSIDIARIES TO MAKE DIVIDENDS, ADVANCES AND LOANS TO DUKE ENERGY
As a condition to the approval of merger transactions, the NCUC, PSCSC, PUCO, KPSC and IURC imposed conditions on the ability of Duke Energy Carolinas, Duke Energy Progress, Duke Energy Ohio, Duke Energy Kentucky, Duke Energy Indiana and Piedmont to transfer funds to Duke Energy through loans or advances, as well as restricted amounts available to pay dividends to Duke Energy. Certain subsidiaries may transfer funds to the Parent by obtaining approval of the respective state regulatory commissions. These conditions imposed restrictions on the ability of the public utility subsidiaries to pay cash dividends as discussed below.
Duke Energy Progress and Duke Energy Florida also have restrictions imposed by their first mortgage bond indentures, which in certain circumstances, limit their ability to make cash dividends or distributions on common stock. Amounts restricted as a result of these provisions were not material at December 31, 2021.
Duke Energy Indiana has certain dividend restrictions as a result of the minority interest investment agreement entered in January 2021 with GIC. Duke Energy Indiana will declare dividends before the second closing, which is required to be completed no later than January 2023, in accordance with the agreement. See additional information in Note 1.
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, 2021.
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
2021 Coal Ash Settlement
On January 22, 2021, Duke Energy Carolinas and Duke Energy Progress entered into the Coal Combustion Residuals Settlement Agreement (the “CCR Settlement Agreement”) with the North Carolina Public Staff (Public Staff), the North Carolina Attorney General’s Office and the Sierra Club (collectively, the "Settling Parties"), which was filed with the NCUC on January 25, 2021. The CCR Settlement Agreement resolves all coal ash prudence and cost recovery issues in connection with 2019 rate cases filed by Duke Energy Carolinas and Duke Energy Progress with the NCUC, as well as the equitable sharing issue on remand from the 2017 Duke Energy Carolinas and Duke Energy Progress North Carolina rate cases as a result of the December 11, 2020 North Carolina Supreme Court opinion. The settlement also provides clarity on coal ash cost recovery in North Carolina for Duke Energy Carolinas and Duke Energy Progress through January 2030 and February 2030 (the "Term"), respectively.
Duke Energy Carolinas and Duke Energy Progress agreed not to seek recovery of approximately $1 billion of systemwide deferred coal ash expenditures, but will retain the ability to earn a debt and equity return during the amortization period, which shall be five years under the 2019 North Carolina rate cases and will be set by the NCUC in future rate case proceedings. The equity return and the amortization period on deferred coal ash costs under the 2017 Duke Energy Carolinas and Duke Energy Progress North Carolina rate cases will remain unaffected. The equity return on deferred coal ash costs under the 2019 North Carolina rate cases and future rate cases in North Carolina will be set at 150 basis points lower than the authorized return on equity (ROE) then in effect, with a capital structure composed of 48% debt and 52% equity. Duke Energy Carolinas and Duke Energy Progress retain the ability to earn a full WACC return during the deferral period, which is the period from when costs are incurred until they are recovered in rates.
The Settling Parties agreed that execution by Duke Energy Carolinas and Duke Energy Progress of a settlement agreement between themselves and the NCDEQ dated December 31, 2019, (the “DEQ Settlement”) and the coal ash management plans included therein or subsequently approved by DEQ are reasonable and prudent. The Settling Parties retain the right to challenge the reasonableness and prudence of actions taken by Duke Energy Carolinas and Duke Energy Progress and costs incurred to implement the scope of work agreed upon in the DEQ Settlement, after February 1, 2020, and March 1, 2020, for Duke Energy Carolinas and Duke Energy Progress, respectively. The Settling Parties further agreed to waive rights through the Term to challenge the reasonableness or prudence of Duke Energy Carolinas’ and Duke Energy Progress’ historical coal ash management practices, and to waive the right to assert any arguments that future coal ash costs, including financing costs, shall be shared between either company and customers through equitable sharing or any other rate base or return adjustment that shares the revenue requirement burden of coal ash costs not otherwise disallowed due to imprudence.
The Settling Parties agreed to a sharing arrangement for future coal ash insurance litigation proceeds between Duke Energy Carolinas and Duke Energy Progress and North Carolina customers. For more information, see Note 4 "Commitments and Contingencies."
As a result of the CCR Settlement Agreement, Duke Energy Carolinas and Duke Energy Progress recorded a pretax charge of approximately $454 million and $494 million, respectively, in the fourth quarter of 2020 to Impairment of assets and other charges and a reversal of approximately $50 million and $102 million, respectively, to Regulated electric operating revenues on the respective Consolidated Statements of Operations.
The Coal Ash Settlement was approved without modification in the NCUC Orders in the 2019 rate cases on March 31, 2021, and April 16, 2021, for Duke Energy Carolinas and Duke Energy Progress, respectively. The NCUC issued an Order on Remand Accepting CCR Settlement and Affirming Previous Orders Settling Rates and Imposing Penalties in the 2017 rate cases on June 25, 2021.
Carbon Plan
The NCUC is required by North Carolina House Bill 951 (HB 951) to adopt an initial Carbon Plan on or before December 31, 2022. The NCUC has directed Duke Energy Carolinas and Duke Energy Progress to file a proposed Carbon Plan on or before May 16, 2022. Duke Energy Carolinas and Duke Energy Progress cannot predict the outcome of this matter.
Performance-Based Regulation Rules
On February 10, 2022, the NCUC adopted rules to govern the application and review process for the Performance-Based Regulation (PBR) authorized under HB 951. The PBR rules are constructive and consistent with the policy objectives of HB 951.
2020 North Carolina Storm Securitization Filings
On October 26, 2020, Duke Energy Carolinas and Duke Energy Progress filed a joint petition with the NCUC, as agreed to in partial settlements reached in the 2019 North Carolina Rate Cases for Duke Energy Carolinas and Duke Energy Progress, seeking authorization for the financing of the costs of each utility's storm recovery activities required as a result of Hurricane Florence, Hurricane Michael, Hurricane Dorian and Winter Storm Diego. Specifically, Duke Energy Carolinas and Duke Energy Progress requested that the NCUC find that their storm recovery costs and related financing costs are appropriately financed by debt secured by storm recovery property, and that the commission issue financing orders by which each utility may accomplish such financing using a securitization structure. On January 27, 2021, Duke Energy Carolinas, Duke Energy Progress and the Public Staff filed an Agreement and Stipulation of Partial Settlement, subject to review and approval of the NCUC, resolving certain accounting issues, including agreement to support an 18- to 20-year bond period. In the NCUC Orders in the 2019 rate cases issued on March 31, 2021, and April 16, 2021, for Duke Energy Carolinas and Duke Energy Progress, respectively, the reasonableness and prudence of the deferred storm costs was approved. On May 20, 2021, the NCUC issued financing orders authorizing the companies to issue storm recovery bonds, subject to the terms of the financing orders, and approving the Agreement and Stipulation of Partial Settlement in its entirety. The storm recovery bonds were issued by Duke Energy Carolinas and Duke Energy Progress on November 24, 2021.
COVID-19 Filings
North Carolina
Duke Energy Carolinas and Duke Energy Progress filed a joint petition on August 7, 2020, with the NCUC for deferral treatment of incremental costs and the cost of waived customer fees due to the COVID-19 pandemic. On December 29, 2021, the NCUC approved Duke Energy Carolinas' and Duke Energy Progress' joint petition to defer estimated incremental pandemic-related costs, without prejudice, to the NCUC's future determination of the appropriate ratemaking treatment ultimately to be accorded such costs in future rate case proceedings.
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/PaysRecovery/Refund
(in millions)20212020a ReturnPeriod Ends
Regulatory Assets(a)
AROs – coal ash
$1,227 $1,414 (h)(b)
Accrued pension and OPEB(c)
365 427 Yes(i)
Deferred fuel and purchased power
339 42 (e)2023
Storm cost securitized balance, net
232 — 2041
Retired generation facilities(c)
54 11 Yes2023
PISCC(c)
31 32 Yes(b)
Hedge costs deferrals(c)
171 174 Yes(b)
Deferred asset – Lee COLA
296 324 (b)
AMI
140 154 Yes(b)
Customer connect project
66 50 Yes(b)
Vacation accrual
83 84 2022
Storm cost deferrals
22 205 Yes(b)
COR settlement
91 95 Yes(b)
Nuclear deferral
78 88 2023
ABSAT, coal ash basin closure
67 71 Yes(b)
Incremental COVID-19 expenses
51 31 Yes(b)
Deferred severance charges
36 57 2023
Other130 210 (b)
Total regulatory assets3,479 3,469 
Less: current portion544 473 
Total noncurrent regulatory assets$2,935 $2,996 
Regulatory Liabilities(a)
Net regulatory liability related to income taxes(d)
$2,785 $2,874 (b)
Costs of removal(c)
2,009 1,975 Yes(f)
AROs – nuclear and other
2,053 1,512 (b)
Provision for rate refunds(c)
124 170 Yes
Hedge cost deferrals
154 16 (b)
Accrued pension and OPEB(c)
44 32 Yes(i)
Other 516 429 (b)
Total regulatory liabilities7,685 7,008 
Less: current portion487 473 
Total noncurrent regulatory liabilities$7,198 $6,535 
(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 23. 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)    Includes incentives on DSM/EE investments and is recovered through an annual rider mechanism.
(h)    Earns a debt and equity return on coal ash expenditures for North Carolina and South Carolina retail customers as permitted by various regulatory orders.
(i)    Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 22 for additional detail.
2017 North Carolina Rate Case
On August 25, 2017, Duke Energy Carolinas filed an application with the NCUC for a rate increase for retail customers of approximately $647 million. On February 28, 2018, Duke Energy Carolinas and the Public Staff filed an Agreement and Stipulation of Partial Settlement resolving certain portions of the proceeding. Terms of the settlement included an ROE of 9.9% and a capital structure of 52% equity and 48% debt. On June 22, 2018, the NCUC issued an order approving the Stipulation of Partial Settlement and requiring a revenue reduction.
The North Carolina Attorney General and other parties separately filed Notices of Appeal to the North Carolina Supreme Court. The North Carolina Supreme Court consolidated the Duke Energy Carolinas and Duke Energy Progress appeals. On December 11, 2020, the North Carolina Supreme Court issued an opinion, which affirmed, in part, and reversed and remanded, in part, the NCUC’s decisions. In the Opinion, the court upheld the NCUC's decision to include coal ash costs in the cost of service, as well as the NCUC’s discretion to allow a return on the unamortized balance of coal ash costs. The court also remanded to the NCUC a single issue to consider the assessment of support for the Public Staff’s equitable sharing argument. On January 22, 2021, Duke Energy Carolinas and Duke Energy Progress entered into the CCR Settlement Agreement with the Settling Parties, which was filed with the NCUC on January 25, 2021, and approved by the NCUC on March 31, 2021. The NCUC issued an Order on Remand Accepting CCR Settlement and Affirming Previous Orders Setting Rates and Imposing Penalties on June 25, 2021.
2019 North Carolina Rate Case
On September 30, 2019, Duke Energy Carolinas filed an application with the NCUC for a net rate increase for retail customers of approximately $291 million, which represented an approximate 6% increase in annual base revenues. The gross rate case revenue increase request was $445 million, which was offset by an EDIT rider of $154 million to return to customers North Carolina and federal EDIT resulting from recent reductions in corporate tax rates. The request for a rate increase was driven by major capital investments subsequent to the previous base rate case, coal ash pond closure costs, accelerated coal plant depreciation and deferred 2018 storm costs. Duke Energy Carolinas requested rates be effective no later than August 1, 2020.
On March 25, 2020, Duke Energy Carolinas and the Public Staff filed an Agreement and Stipulation of Partial Settlement, subject to review and approval of the NCUC, resolving certain issues in the base rate proceeding. On July 24, 2020, Duke Energy Carolinas filed its request for approval of its notice to customers required to implement temporary rates. On July 27, 2020, Duke Energy Carolinas filed a joint motion with Duke Energy Progress and the Public Staff notifying the commission that the parties reached a joint partial settlement with the Public Staff. Also, on July 27, 2020, Duke Energy Carolinas filed a letter stating that it intended to update its temporary rates calculation to reflect the terms of the partial settlement. On July 31, 2020, Duke Energy Carolinas and the Public Staff filed a Second Agreement and Stipulation of Partial Settlement (Second Partial Settlement), subject to review and approval of the NCUC, resolving certain remaining issues in the base rate proceeding. The remaining items litigated at hearing included recovery of deferred coal ash compliance costs that are subject to asset retirement obligation accounting, implementation of new depreciation rates and the amortization period of the loss on the hydro station sale.
On August 4, 2020, Duke Energy Carolinas filed an amended motion for approval of its amended notice to customers, seeking to exercise its statutory right to implement temporary rates subject to refund on or after August 24, 2020. The revenue requirement to be recovered, subject to refund, through the temporary rates was based on and consistent with the base rate component of the Second Partial Settlement and excluded the items to be litigated noted above. The NCUC approved the August 4, 2020 amended temporary rates motion on August 6, 2020, and temporary rates went into effect on August 24, 2020.
The Duke Energy Carolinas evidentiary hearing concluded on September 18, 2020, and post-hearing filings were made with the NCUC from all parties by November 4, 2020. On January 22, 2021, Duke Energy Carolinas and Duke Energy Progress entered into the CCR Settlement Agreement with the Settling Parties, which was filed with the NCUC on January 25, 2021.
On March 31, 2021, the NCUC issued an order approving the March 25, 2020, and July 31, 2020, partial settlements. The order includes approval of 1) an ROE of 9.6% based upon a capital structure of 52% equity and 48% debt; 2) deferral treatment of approximately $800 million of grid improvement projects with a return; 3) a flow back period of five years for unprotected federal EDIT; and 4) the reasonableness and prudence of $213 million of deferred storm costs, which were removed from the rate case and for which Duke Energy Carolinas filed a petition seeking securitization in October 2020. Additionally, the order approved without modification the CCR Settlement Agreement.
The order denied Duke Energy Carolinas' proposal to shorten the remaining depreciable lives of certain Duke Energy Carolinas coal-fired generating units, indicating the NCUC has not had the chance to fully examine the issue within the context of an integrated resource planning (IRP) proceeding, and upon retirement the remaining net book value of these units should be placed in a regulatory asset account to be amortized over an appropriate period to be determined in a future rate case.
On May 21, 2021, the NCUC issued an Order Approving Rate Schedules, which resulted in a net increase of approximately $33 million. Revised customer rates became effective on June 1, 2021.
2018 South Carolina Rate Case
On November 8, 2018, Duke Energy Carolinas filed an application with the PSCSC for a rate increase for retail customers of approximately $168 million.
After hearings in March 2019, the PSCSC issued an order on May 21, 2019, which included an ROE of 9.5% and a capital structure of 53% equity and 47% debt. The order also included the following material components:
•Approval of cancellation of the Lee Nuclear Project, with Duke Energy Carolinas maintaining the combined operating license;
•Approval of recovery of $125 million (South Carolina retail portion) of Lee Nuclear Project development costs (including AFUDC through December 2017) over a 12-year period, but denial of a return on the deferred balance of costs;
•Approval of recovery of $96 million of coal ash costs over a five-year period with a return at Duke Energy Carolinas' WACC;
•Denial of recovery of $115 million of certain coal ash costs deemed to be related to the Coal Ash Act and incremental to the federal CCR rule;
•Approval of a $66 million decrease to base rates to reflect the change in ongoing tax expense, primarily the reduction in the federal income tax rate from 35% to 21%;
•Approval of a $45 million decrease through the EDIT Rider to return EDIT resulting from the federal tax rate change and deferred revenues since January 2018 related to the change, to be returned in accordance with the Average Rate Assumption Method (ARAM) for protected EDIT, over a 20-year period for unprotected EDIT associated with Property, Plant and Equipment, over a five-year period for unprotected EDIT not associated with Property, Plant and Equipment and over a five-year period for the deferred revenues; and
•Approval of a $17 million decrease through the EDIT Rider related to reductions in the North Carolina state income tax rate from 6.9% to 2.5% to be returned over a five-year period.
As a result of the order, revised customer rates were effective June 1, 2019. On May 31, 2019, Duke Energy Carolinas filed a Petition for Rehearing or Reconsideration of that order contending substantial rights of Duke Energy Carolinas were prejudiced by unlawful, arbitrary and capricious rulings by the PSCSC on certain issues presented in the proceeding. On June 19, 2019, the PSCSC issued a directive denying Duke Energy Carolinas' request to rehear or reconsider the commission's rulings on certain issues presented in the proceeding including coal ash remediation and disposal costs, ROE and the recovery of a return on deferred operation and maintenance expenses. An order detailing the commission's decision in the directive was issued on October 18, 2019. Duke Energy Carolinas filed a notice of appeal on November 15, 2019, with the Supreme Court of South Carolina. On November 20, 2019, the South Carolina Energy Users Committee filed a Notice of Appeal with the Supreme Court of South Carolina. Initial briefs were filed on April 21, 2020, which included the South Carolina Energy User's Committee brief arguing that the PSCSC erred in allowing Duke Energy Carolinas' recovery of costs related to the Lee Nuclear Station. Response briefs were filed on July 6, 2020, and reply briefs were filed on August 11, 2020. Oral arguments were heard before the Supreme Court of South Carolina on May 26, 2021.
On October 27, 2021, the Supreme Court of South Carolina affirmed the PSCSC's May 2019 order to:
•Disallow cost recovery on certain CCR compliance costs the PSCSC deemed to be incremental to the federal CCR rules;
•Disallow recovery of certain coal ash insurance litigation expenses;
•Disallow a return on certain deferred expenses; and
•Allow recovery of Lee Nuclear Project preconstruction costs.
The Supreme Court of South Carolinas' decision notes the prior determination made by the PSCSC that Duke Energy could submit coal ash costs for recovery that were not initially approved in the rate case order if such costs can be attributed to the CCR rules. As a result of the court's opinion, Duke Energy Carolinas recognized a pretax charge of approximately $160 million to Impairment of assets and other charges, and a $31 million increase in Other income and expenses, net in the Consolidated Statements of Operations for the year ended December 31, 2021, principally related to coal ash remediation at retired coal ash basin sites. On November 29, 2021, Duke Energy Carolinas filed a petition for rehearing on several grounds, including the Supreme Court of South Carolinas’ decision on coal ash cost recovery and certain deferred expenses. On February 1, 2022, the Supreme Court of South Carolina denied the petition for rehearing.
Oconee Nuclear Station Subsequent License Renewal
On June 7, 2021, Duke Energy Carolinas filed a subsequent license renewal 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 subsequent license renewal would extend operations of the facility from 60 to 80 years. The current license 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 purporting to challenge Duke Energy Carolinas’ environmental report (ER). In general, the proposed contentions claimed that the ER did not consider certain information regarding the environmental aspects of severe accidents caused by a hypothetical failure of the Jocassee Dam, and therefore did not satisfy the National Environmental Policy Act (NEPA) of 1969, as amended, or the NRC’s NEPA-implementing regulations. Duke Energy Carolinas filed its answer to the proposed contentions on October 22, 2021, and the Petitioners filed their reply to Duke Energy Carolinas’ answer on November 5, 2021. 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.
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 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/PaysRecovery/Refund
(in millions)20212020a ReturnPeriod Ends
Regulatory Assets(a)
AROs – coal ash
$1,389 $1,347 (h)(b)
AROs – nuclear and other
613 683 (c)
Accrued pension and OPEB
351 393 (k)
Deferred fuel and purchased power
303 158 (f)2023
Storm cost securitized balance, net
759 — 2041
Retired generation facilities
171 189 Yes(b)
PISCC and deferred operating expenses
47 51 Yes2054
Hedge costs deferrals
60 89 (b)
Deferred asset – Harris COLA
21 32 (b)
AMI
92 57 Yes(b)
Customer connect project
57 25 Yes(b)
DSM/EE(e)
218 224 (i)(i)
Vacation accrual
42 42 2022
Storm cost deferrals(d)
170 785 Yes(b)
NCEMPA deferrals
165 124 (g)2042
COR settlement
32 33 Yes(b)
Nuclear deferral
42 35 2023
ABSAT, coal ash basin closure
23 27 Yes(b)
Incremental COVID-19 expenses
28 23 Yes(b)
Deferred severance charges
18 29 2023
Other50 122 (b)
Total regulatory assets4,651 4,468 
Less: current portion533 492 
Total noncurrent regulatory assets$4,118 $3,976 
Regulatory Liabilities(a)
Net regulatory liability related to income taxes(l)
$1,695 $1,662 (b)
Costs of removal
2,955 2,666 Yes(j)
Provision for rate refunds
87 123 Yes
Hedge cost deferrals
117 8 (b)
Other 395 465 (b)
Total regulatory liabilities5,249 4,924 
Less: current portion381 530 
Total noncurrent regulatory liabilities$4,868 $4,394 
(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)    South Carolina storm costs are included in rate base.
(e)    Included in rate base.
(f)    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.
(g)    South Carolina retail allocated costs are earning a return.
(h)    Earns a debt and equity return on coal ash expenditures for North Carolina and South Carolina retail customers as permitted by various regulatory orders.
(i)    Includes incentives on DSM/EE investments and is recovered through an annual rider mechanism.
(j)    Recovered over the life of the associated assets.
(k)    Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 22 for additional detail.
(l)    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 23. Portions are included in rate base.
2017 North Carolina Rate Case
On June 1, 2017, Duke Energy Progress filed an application with the NCUC for a rate increase for retail customers of approximately $477 million, which was subsequently adjusted to $420 million. On November 22, 2017, Duke Energy Progress and the Public Staff filed an Agreement and Stipulation of Partial Settlement resolving certain portions of the proceeding. Terms of the settlement included an ROE of 9.9% and a capital structure of 52% equity and 48% debt. On February 23, 2018, the NCUC issued an order approving the stipulation. The Public Staff, the North Carolina Attorney General and the Sierra Club filed notices of appeal to the North Carolina Supreme Court.
The North Carolina Supreme Court consolidated the Duke Energy Carolinas and Duke Energy Progress appeals. On December 11, 2020, the North Carolina Supreme Court issued an opinion, which affirmed, in part, and reversed and remanded, in part, the NCUC’s decisions. In the Opinion, the court upheld the NCUC's decision to include coal ash costs in the cost of service, as well as the NCUC’s discretion to allow a return on the unamortized balance of coal ash costs. The court also remanded to the NCUC a single issue to consider the assessment of support for the Public Staff’s equitable sharing argument. On January 22, 2021, Duke Energy Progress and Duke Energy Carolinas entered into the CCR Settlement Agreement with the Settling Parties, which was filed with the NCUC on January 25, 2021, and approved by the NCUC on April 16, 2021. The NCUC issued an Order on Remand Accepting CCR Settlement and Affirming Previous Orders Setting Rates and Imposing Penalties on June 25, 2021.
2019 North Carolina Rate Case
On October 30, 2019, Duke Energy Progress filed an application with the NCUC for a net rate increase for retail customers of approximately $464 million, which represented an approximate 12.3% increase in annual base revenues. The gross rate case revenue increase request was $586 million, which was offset by riders of $122 million, primarily an EDIT rider of $120 million to return to customers North Carolina and federal EDIT resulting from recent reductions in corporate tax rates. The request for a rate increase was driven by major capital investments subsequent to the previous base rate case, coal ash pond closure costs, accelerated coal plant depreciation and deferred 2018 storm costs. Duke Energy Progress sought to defer and recover incremental Hurricane Dorian storm costs in this proceeding and requested rates be effective no later than September 1, 2020. As a result of the COVID-19 pandemic, on March 24, 2020, the NCUC suspended the procedural schedule and postponed the previously scheduled evidentiary hearing on this matter indefinitely.
On June 2, 2020, Duke Energy Progress and the Public Staff filed an Agreement and Stipulation of Partial Settlement, subject to review and approval of the NCUC, resolving certain issues in the base rate proceeding. On July 27, 2020, Duke Energy Progress filed a joint motion with Duke Energy Carolinas and the Public Staff notifying the commission that the parties reached a joint partial settlement with the Public Staff. On July 31, 2020, Duke Energy Progress and the Public Staff filed a Second Agreement and Stipulation of Partial Settlement, subject to review and approval of the NCUC, resolving certain remaining issues in the base rate proceeding. The remaining items litigated at hearing included recovery of deferred coal ash compliance costs that are subject to asset retirement obligation accounting and implementation of new depreciation rates.
On August 7, 2020, Duke Energy Progress filed a motion for approval of notice required to implement temporary rates, seeking to exercise its statutory right to implement temporary rates subject to refund on or after September 1, 2020. The revenue requirement to be recovered subject to refund through the temporary rates was based on and consistent with the terms of the base rate component of the settlement agreements with the Public Staff and excluded items to be litigated noted above. In addition, Duke Energy Progress also sought authorization to place a temporary decrement EDIT Rider into effect, concurrent with the temporary base rate change. The NCUC approved the August 7, 2020 temporary rates motion on August 11, 2020, and temporary rates went into effect on September 1, 2020.
On January 22, 2021, Duke Energy Progress and Duke Energy Carolinas entered into the CCR Settlement Agreement with the Settling Parties, which was filed with the NCUC on January 25, 2021.
On April 16, 2021, the NCUC issued an order approving the June 2, 2020, and July 31, 2020, partial settlements. The order includes approval of 1) an ROE of 9.6% based upon a capital structure of 52% equity and 48% debt; 2) deferral treatment of approximately $400 million of grid improvement projects with a return; 3) a flow back period of five years for unprotected federal EDIT; and 4) the reasonableness and prudence of approximately $714 million of deferred storm costs, which were removed from the rate case and for which Duke Energy Progress filed a petition seeking securitization in October 2020. Additionally, the order approved without modification the CCR Settlement Agreement.
The order denied Duke Energy Progress' proposal to shorten the remaining depreciable lives of certain Duke Energy Progress coal-fired generating units, indicating the NCUC has not had the chance to fully examine the issue within the context of an IRP proceeding, and upon retirement the remaining net book value of these units should be placed in a regulatory asset account to be amortized over an appropriate period to be determined in a future rate case.
On May 21, 2021, the NCUC issued an Order Approving Rate Schedules, which resulted in a net increase of approximately $178 million. Revised customer rates became effective on June 1, 2021.
2018 South Carolina Rate Case
On November 8, 2018, Duke Energy Progress filed an application with the PSCSC for a rate increase for retail customers of approximately $59 million.
After hearings in April 2019, the PSCSC issued an order on May 21, 2019, which included an ROE of 9.5% and a capital structure of 53% equity and 47% debt. The order also included the following material components:
•Approval of recovery of $4 million of coal ash costs over a five-year period with a return at Duke Energy Progress' WACC;
•Denial of recovery of $65 million of certain coal ash costs deemed to be related to the Coal Ash Act and incremental to the federal CCR rule;
•Approval of a $17 million decrease to base rates to reflect the change in ongoing tax expense, primarily the reduction in the federal income tax rate from 35% to 21%;
•Approval of a $12 million decrease through the EDIT Tax Savings Rider resulting from the federal tax rate change and deferred revenues since January 2018 related to the change, to be returned in accordance with ARAM for protected EDIT, over a 20-year period for unprotected EDIT associated with Property, Plant and Equipment, over a five-year period for unprotected EDIT not associated with Property, Plant and Equipment and over a three-year period for the deferred revenues; and
•Approval of a $12 million increase due to the expiration of EDIT related to reductions in the North Carolina state income tax rate from 6.9% to 2.5%.
As a result of the order, revised customer rates were effective June 1, 2019. On May 31, 2019, Duke Energy Progress filed a Petition for Rehearing or Reconsideration of that order contending substantial rights of Duke Energy Progress were prejudiced by unlawful, arbitrary and capricious rulings by the PSCSC on certain issues presented in the proceeding. On June 19, 2019, the PSCSC issued a directive denying Duke Energy Progress' request to rehear or reconsider the commission's rulings on certain issues presented in the proceeding including coal ash remediation and disposal costs, ROE and the recovery of a return on deferred operation and maintenance expenses, but allowing additional litigation-related costs. As a result of the directive allowing litigation-related costs, customer rates were revised effective July 1, 2019. An order detailing the commission's decision in the directive was issued on October 18, 2019. In November 2019, Duke Energy Progress appealed the decision to the Supreme Court of South Carolina.
On October 27, 2021, the Supreme Court of South Carolina affirmed the PSCSC's May 2019 order to:
•Disallow cost recovery on certain CCR compliance costs the PSCSC deemed to be incremental to the federal CCR rules;
•Disallow recovery of certain coal ash insurance litigation expenses; and
•Disallow a return on certain deferred expenses.
The Supreme Court of South Carolinas' decision notes the prior determination made by the PSCSC that Duke Energy could submit coal ash costs for recovery that were not initially approved in the rate case order if such costs can be attributed to the CCR rules. As a result of the court's opinion, Duke Energy Progress recognized a pretax charge of approximately $42 million to Impairment of assets and other charges, and a $6 million increase in Other income and expenses, net, in the Consolidated Statements of Operations for the year ended December 31, 2021, principally related to coal ash remediation at retired coal ash basin sites. On November 29, 2021, Duke Energy Progress filed a petition for rehearing on several grounds, including the Supreme Court of South Carolinas’ decision on coal ash cost recovery and certain deferred expenses. On February 1, 2022, the Supreme Court of South Carolina denied the petition for rehearing.
FERC Return on Equity Complaints
On October 11, 2019, North Carolina Eastern Municipal Power Agency (NCEMPA) 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 contained in the demand formula rate in the Full Requirements Power Purchase Agreement (FRPPA) between NCEMPA and Duke Energy Progress is unjust and unreasonable. On July 16, 2020, the FERC set this matter for hearing and settlement judge procedures and established a refund effective date of October 11, 2019. In its order setting the matter for settlement, the FERC allowed for the consideration of variations to the base transmission-related ROE methodology developed in its Order No. 569-A, through the introduction of “specific facts and circumstances” involving issues specific to the case. The parties reached a settlement in principle at a settlement conference on January 7, 2021, and filed a settlement package on March 10, 2021. The FERC Trial Staff filed comments in support of the settlement. On April 19, 2021, the Settlement Judge certified the settlement to the FERC as an uncontested settlement. The FERC approved the settlement on May 25, 2021, and Duke Energy Progress filed compliance documents on June 10, 2021. The FERC accepted the compliance filing on October 8, 2021.
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 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. Under FPA Section 206, the earliest refund effective date that the FERC can establish is the date of the filing of the complaint. Duke Energy Progress responded to the complaint on November 20, 2020, seeking dismissal, demonstrating that the 11% ROE is just and reasonable for the service provided. The parties filed responsive pleadings and are awaiting an order from the FERC. Duke Energy Progress cannot predict the outcome of this matter.
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/PaysRecovery/Refund
(in millions)20212020a ReturnPeriod Ends
Regulatory Assets(a)
AROs – coal ash
$10 $10 (b)
AROs – nuclear and other
7 2 (b)
Accrued pension and OPEB(c)
374 482 Yes(g)
Deferred fuel and purchased power
415 4 (f)2022
Nuclear asset securitized balance, net
937 991 2036
Retired generation facilities(c)
94 174 Yes2044
Hedge costs deferrals(c)
77 59 Yes2038
AMI(c)
38 45 Yes2032
Customer connect project
67 30 2037
DSM/EE(c)
12 17 Yes2025
Storm cost deferrals(c)
19 108 (e)(b)
Costs of removal regulatory asset(c)
107 — (d)(b)
Qualifying facility contract buyouts(c)
94 107 Yes2034
Other37 35 (d)(b)
Total regulatory assets2,288 2,064 
Less: current portion497 265 
Total noncurrent regulatory assets$1,791 $1,799 
Regulatory Liabilities(a)
Net regulatory liability related to income taxes(c)
$699 $749 (b)
Other 97 19 (d)(b)
Total regulatory liabilities796 768 
Less: current portion98 110 
Total noncurrent regulatory liabilities$698 $658 
(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 22 for additional detail.
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%. Duke Energy Florida will also be able to retain the retail portion of the DOE award of approximately $173 million for spent nuclear fuel, which is expected to be received in 2022, in order to mitigate customer rates over the term of the 2021 Settlement. In return, Duke Energy Florida will be able to recognize the $173 million into earnings from 2022 through 2024.
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.
Storm Restoration Cost Recovery
Duke Energy Florida filed a petition with the FPSC on April 30, 2019, to recover $223 million of estimated retail incremental storm restoration costs for Hurricane Michael, consistent with the provisions in the 2017 Settlement, and the FPSC approved the petition on June 11, 2019. The FPSC also approved allowing Duke Energy Florida to use the tax savings resulting from the Tax Act to recover these storm costs in lieu of implementing a storm surcharge. Approved storm costs were fully recovered by year-end 2021. On November 22, 2019, Duke Energy Florida filed a petition for approval of actual retail recoverable storm restoration costs related to Hurricane Michael in the amount of $191 million plus interest. On May 19, 2020, Duke Energy Florida filed a supplemental true up reducing the actual retail recoverable storm restoration costs related to Hurricane Michael by approximately $3 million, resulting in a total request to recover $188 million actual retail recoverable storm restoration costs, plus interest. Approximately $80 million of these costs are included in Regulatory assets within Current Assets and Other Noncurrent Assets on the Consolidated Balance Sheets as of December 31, 2020.
Duke Energy Florida filed a petition with the FPSC on December 19, 2019, to recover $169 million of estimated retail incremental storm restoration costs for Hurricane Dorian, consistent with the provisions in the 2017 Settlement and the FPSC approved the petition on February 24, 2020. The final actual amount of $145 million was filed on September 30, 2020. The 2021 Settlement resolved all matters regarding storm cost recovery relating to Hurricane Michael and Hurricane Dorian.
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 over the next three years, and this investment will be included in base rates offset by the revenue from the subscription fees. 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. LULAC's initial brief was filed on May 26, 2021, and Appellees' response briefs were filed on July 26, 2021. LULAC's reply brief was filed on September 24, 2021, and its request for oral argument was filed on September 28, 2021. The Supreme Court of Florida heard the oral argument on February 9, 2022. The FPSC approval order remains in effect pending the outcome of the appeal. 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/PaysRecovery/Refund
(in millions)20212020a ReturnPeriod Ends
Regulatory Assets(a)
AROs – coal ash
$33 $22 Yes(b)
Accrued pension and OPEB
133 149 (g)
Deferred fuel and purchased power
38 — 2022
PISCC and deferred operating expenses(c)
16 16 Yes2083
Hedge costs deferrals
5 7 (b)
AMI
24 36 (b)
Customer connect project
41 26 (b)
DSM/EE
5 1 (f)(e)
Vacation accrual
6 6 2022
Storm cost deferrals
2 4 2023
CEP deferral
161 117 Yes(b)
Deferred pipeline integrity costs
24 21 Yes(b)
MGP
104 104 (b)
Other115 140 (b)
Total regulatory assets707 649 
Less: current portion72 39 
Total noncurrent regulatory assets$635 $610 
Regulatory Liabilities(a)
Net regulatory liability related to income taxes
$602 $628 (b)
Costs of removal
39 68 (d)
Provision for rate refunds
61 45 (b)
Accrued pension and OPEB
21 17 (g)
Other 78 55 (b)
Total regulatory liabilities801 813 
Less: current portion62 65 
Total noncurrent regulatory liabilities$739 $748 
(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 via a rider mechanism.
(f)    Includes incentives on DSM/EE investments.
(g)    Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 22 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 (DCI) Rider. Duke Energy Ohio anticipates the PUCO will rule on the request by the summer of 2022. Duke Energy Ohio cannot predict the outcome of this matter.
Ohio House Bill 6 and House Bill 128
On July 23, 2019, House Bill 6 was signed into law and became effective January 1, 2020. Among other things, the bill allowed for funding through a rider mechanism referred to as the Clean Air Fund (CAF) Rider, of two nuclear generating facilities located in Northern Ohio owned by Energy Harbor (f/k/a FirstEnergy Solutions) and certain renewable resources, repeal of energy efficiency mandates and recovery of prudently incurred costs, net of any revenues, for Ohio investor-owned utilities that are participants under the OVEC power agreement. The OVEC recovery is through a non-bypassable rider that replaced any existing recovery mechanism approved by the PUCO and will remain in place through 2030. As such, Duke Energy Ohio created the Legacy Generation Rider that replaced the Price Stabilization Rider effective January 1, 2020. The amounts recoverable from customers are subject to an annual cap, with incremental costs that exceed such cap eligible for deferral and recovery, subject to review. See Note 17 for additional discussion of Duke Energy Ohio's ownership interest in OVEC. House Bill 128 (HB 128) was signed into law on March 31, 2021, and became effective June 30, 2021. The bill removes nuclear plant funding included in HB 6, eliminates the CAF Rider and establishes the Solar Generation Fund Rider to recover the renewable investments originally included in HB 6. HB 128 does not impact OVEC cost recovery or any transmission or distribution rider.
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. The 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 issued an entry for each utility to file by July 15, 2021, a proposal to reestablish low-income programs through December 31, 2021. Duke Energy Oho filed its application on July 14, 2021.
Duke Energy Ohio cannot predict the outcome of this matter.
Natural Gas Pipeline Extension
Duke Energy Ohio is installing 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. Duke Energy Ohio currently estimates the pipeline development costs and construction activities will range from $185 million to $195 million in direct costs (excluding overheads and AFUDC) and that construction of the pipeline extension will be completed in February 2022. An evidentiary hearing on Duke Energy Ohio's application for a Certificate of Environmental Compatibility and Public Need concluded on April 11, 2019. On November 21, 2019, the Ohio Power Siting Board (OPSB) approved Duke Energy Ohio's application subject to 41 conditions on construction. Applications for rehearing were filed by several stakeholders on December 23, 2019, arguing that the OPSB approval was incorrect. On February 20, 2020, the OPSB denied the rehearing requests. On April 15, 2020, those stakeholders filed a notice of appeal at the Supreme Court of Ohio of the OPSB’s decision approving Duke Energy Ohio’s Central Corridor Project application. The Supreme Court of Ohio affirmed the OPSB order on September 22, 2021.
On September 22, 2020, Duke Energy Ohio filed an application with the OPSB for approval to amend the certificated pipeline route due to changes in the route negotiated with property owners and municipalities. On January 21, 2021, the OPSB approved the amended filing with recommended conditions that reaffirm previous conditions and provide guidance regarding local permitting and construction supervision.
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 has collected approximately $55 million in environmental remediation costs incurred between 2008 through 2012 through Rider MGP, which is currently suspended. Duke Energy Ohio has 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. To date, the PUCO has not ruled on Duke Energy Ohio’s annual applications for the calendar years 2013 through 2019. On September 28, 2018, the Staff of the PUCO (Staff) issued a report recommending a disallowance of approximately $12 million of the $26 million in MGP remediation costs incurred between 2013 through 2017 that the Staff believes are not eligible for recovery. The Staff interprets the PUCO’s 2013 order granting Duke Energy Ohio recovery of MGP remediation as limiting the recovery to work directly on the East End and West End sites. On October 30, 2018, Duke Energy Ohio filed reply comments objecting to the Staff’s recommendations and explaining, among other things, the obligation Duke Energy Ohio has under Ohio law to remediate all areas impacted by the former MGPs and not just physical property that housed the former plants and equipment. On March 29, 2019, Duke Energy Ohio filed its annual application to recover incremental remediation expense for the calendar year 2018 seeking recovery of approximately $20 million in remediation costs. On July 12, 2019, the Staff recommended a disallowance of approximately $11 million for work that the Staff believes occurred in areas not authorized for recovery. Additionally, the Staff recommended that any discussion pertaining to Duke Energy Ohio's recovery of ongoing MGP costs should be directly tied to or netted against insurance proceeds collected by Duke Energy Ohio. An evidentiary hearing concluded on November 21, 2019. Initial briefs were filed on January 17, 2020, and reply briefs were filed on February 14, 2020.
On March 31, 2020, Duke Energy Ohio filed its annual application to recover incremental MGP remediation expense seeking recovery of approximately $39 million in remediation costs incurred during 2019. On July 23, 2020, the Staff recommended a disallowance of approximately $4 million for work the Staff believes occurred in areas not authorized for recovery. Additionally, the Staff recommended insurance proceeds, net of litigation costs and attorney fees, should be paid to customers and not be held by Duke Energy Ohio until all investigation and remediation is complete. Duke Energy Ohio filed comments in response to the Staff's report on August 21, 2020, and intervenor comments were filed on November 9, 2020.
The 2013 PUCO order also contained conditional deadlines for completing the MGP environmental remediation and the deferral of related remediation costs. Subsequent to the order, the deadline was extended to December 31, 2019. On May 10, 2019, Duke Energy Ohio filed an application requesting a continuation of its existing deferral authority for MGP remediation that must occur after December 31, 2019. On July 12, 2019, the Staff recommended the commission deny the deferral authority request. On September 13, 2019, intervenor comments were filed opposing Duke Energy Ohio's request for continuation of existing deferral authority and on October 2, 2019, Duke Energy Ohio filed reply comments.
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 is subject to review and approval by the PUCO. If approved, the Stipulation and Recommendation would, among other things, resolve 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 as it relates to Duke Energy Ohio’s natural gas operations. These impacts are not expected to have a material impact on Duke Energy Ohio's financial statements. The Stipulation and Recommendation further acknowledges 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 October 15, 2021, the PUCO granted motions to intervene filed in September 2021 by Interstate Gas Supply, Inc. and Retail Energy Supply Association on a limited basis. An evidentiary hearing was held on November 18, 2021, and briefing was concluded on December 23, 2021. 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. Duke Energy Ohio requested commission approval to implement the tariff changes and rider effective April 1, 2019. The new rider will 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 will be refunded consistent with federal law and deferred income taxes not subject to normalization rules will be refunded over a 10-year period. The PUCO established a procedural schedule and testimony was filed on July 31, 2019. An evidentiary hearing occurred on August 7, 2019. Initial briefs were filed on September 11, 2019. Reply briefs were filed on September 25, 2019. The Stipulation and Recommendation filed on August 31, 2021, disclosed in the MGP Cost Recovery matter above, also resolves the outstanding issues in this proceeding. On October 15, 2021, the PUCO granted motions to intervene filed in September 2021 by Interstate Gas Supply, Inc. and Retail Energy Supply Association on a limited basis. An evidentiary hearing was held on November 18, 2021, and briefing was concluded on December 23, 2021. Duke Energy Ohio cannot predict the outcome of this matter.
Duke Energy Kentucky Natural Gas Base Rate Case
On June 1, 2021, Duke Energy Kentucky filed an application with the KPSC requesting an increase in natural gas base rates of approximately $15 million, an approximate 13% average increase across all customer classes. The drivers for this case are capital invested since Duke Energy Kentucky's last natural gas base rate case in 2018. Duke Energy Kentucky also sought implementation of a rider in order to recover from or pay to customers the financial impact of governmental directives and mandates, including changes in federal or state tax rates and regulations issued by the Pipeline and Hazardous Materials Safety Administration (PHMSA). On October 8, 2021, Duke Energy Kentucky filed a Stipulation and Recommendation jointly with the Kentucky Attorney General, subject to review and approval by the KPSC, which if approved, would resolve the case. The Stipulation and Recommendation included a $9 million increase in base revenues, an ROE of 9.375% for natural gas base rates and 9.3% for natural gas riders, a rider for PHMSA-required capital investments with an annual 5% rate increase cap and a four-year natural gas base rate case stay out. The evidentiary hearing was held on October 18, 2021. On December 28, 2021, the KPSC approved the Stipulation and Recommendation with minor modifications, authorizing a $9 million increase. Rates were effective January 4, 2022.
Midwest Propane Caverns
Duke Energy Ohio uses propane stored in caverns to meet peak demand during winter. Once the Central Corridor Project is complete, the propane peaking facilities will no longer be necessary and will be 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 but not for the net book value of the remaining 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 in the fourth quarter of 2021. There is approximately $6 million and $27 million in Net, property, plant and equipment on the Consolidated Balance Sheets as of December 31, 2021, and December 31, 2020, respectively, related to the propane caverns. The PUCO established a procedural schedule for the submission of comments by March 7, 2022. Duke Energy Ohio cannot predict the outcome of this matter.
Regional Transmission Organization Realignment
Duke Energy Ohio, including Duke Energy Kentucky, transferred control of its transmission assets from MISO to PJM, effective December 31, 2011. The PUCO approved a settlement related to Duke Energy Ohio’s recovery of certain costs of the RTO realignment via a non-bypassable rider. Duke Energy Ohio is allowed to recover all MISO Transmission Expansion Planning (MTEP) costs directly or indirectly charged to Ohio customers. The KPSC also approved a request to effect the RTO realignment, subject to a commitment not to seek double recovery in a future rate case of the transmission expansion fees that may be charged by MISO and PJM in the same period or overlapping periods.
The following table provides a reconciliation of the beginning and ending balance of Duke Energy Ohio’s recorded liability for its exit obligation and share of MTEP costs recorded in Other within Current Liabilities and Other Noncurrent Liabilities on the Consolidated Balance Sheets. The retail portions of MTEP costs billed by MISO are recovered by Duke Energy Ohio through a non-bypassable rider. As of December 31, 2021, and 2020, $33 million and $37 million, respectively, are recorded in Regulatory assets on Duke Energy Ohio's Consolidated Balance Sheets.
Provisions/
Cash
(in millions)
December 31, 2020
Adjustments
Reductions
December 31, 2021
Duke Energy Ohio
$50 $— $(4)$46 
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/PaysRecovery/Refund
(in millions)20212020a ReturnPeriod Ends
Regulatory Assets(a)
AROs – coal ash
$749 $615 Yes(b)
Accrued pension and OPEB
222 245 (e)
Deferred fuel and purchased power
158 9 2022
Retired generation facilities(c)
38 43 Yes2030
PISCC and deferred operating expenses(c)
262 298 Yes(b)
Hedge costs deferrals
35 22 (b)
AMI
17 19 2031
Customer connect project
11 5 (b)
Vacation accrual
13 12 2022
Other50 60 (b)
Total regulatory assets1,555 1,328 
Less: current portion277 125 
Total noncurrent regulatory assets$1,278 $1,203 
Regulatory Liabilities(a)
Net regulatory liability related to income taxes
$908 $956 (b)
Costs of removal
575 599 (d)
Accrued pension and OPEB
113 100 (e)
Other 96 83 (b)
Total regulatory liabilities1,692 1,738 
Less: current portion127 111 
Total noncurrent regulatory liabilities$1,565 $1,627 
(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 22 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. Hearings concluded on February 7, 2020. 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% is 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 are estimated to be the remaining 25% of the total rate increase. Step two rates were approved on July 28, 2021, and implemented in August 2021. Step two rates are based on a return on equity of 9.7% and actual December 31, 2020 capital structure with a 54% equity component. Step two rates will be reconciled to January 1, 2021. Several groups appealed the IURC order to the Indiana Court of Appeals. Appellate briefs were filed on October 14, 2020, focusing on three issues: wholesale sales allocations, coal ash basin cost recovery and the Edwardsport IGCC operating and maintenance expense level approved. The appeal was fully briefed in January 2021, and an oral argument was held on April 8, 2021. The Indiana Court of Appeals affirmed the IURC decision on May 13, 2021. The Indiana Office of Utility Consumer Counselor (OUCC) and the Duke Industrial Group filed a joint petition to transfer the rate case appeal to the Indiana Supreme Court on June 28, 2021. Response briefs were filed July 19, 2021. The Indiana Supreme Court granted the petition to transfer on September 16, 2021, and oral arguments were heard on November 16, 2021. 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 approved coal ash basin closure costs expended through 2018 including financing costs as a regulatory asset and included in rate base. 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 filed a notice of appeal to the Indiana Court of Appeals on December 3, 2021. 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/PaysRecovery/Refund
(in millions)20212020a ReturnPeriod Ends
Regulatory Assets(a)
AROs – nuclear and other
$22 $20 (d)
Accrued pension and OPEB(c)
82 88 (g)
Vacation accrual
12 12 2022
Derivatives – natural gas supply contracts(f)
139 122 
Deferred pipeline integrity costs(c)
84 71 2025
Amounts due from customers
85 110 (e)(b)
Other33 32 (b)
Total regulatory assets457 455 
Less: current portion141 153 
Total noncurrent regulatory assets$316 $302 
Regulatory Liabilities(a)
Net regulatory liability related to income taxes
$510 $499 (b)
Costs of removal(c)
572 575 (d)
Provision for rate refunds
2 6 
Accrued pension and OPEB(c)
5 3 (g)
Other 25 49 (e)(b)
Total regulatory liabilities1,114 1,132 
Less: current portion56 88 
Total noncurrent regulatory liabilities$1,058 $1,044 
(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 22 for additional detail.
2020 Tennessee Rate Case
On July 2, 2020, Piedmont filed an application with the TPUC, its first general rate case in Tennessee in nine years, for a rate increase for retail customers of approximately $30 million, which represents an approximate 15% increase in annual revenues. The rate increase is driven by significant infrastructure upgrade investments since Piedmont's previous rate case. Approximately half of the plant additions being added to rate base are categories of capital investment not covered under the IMR mechanism, which was approved in 2013. Piedmont amended its requested increase to approximately $26 million in December 2020. As authorized under Tennessee law, Piedmont implemented interim rates on January 2, 2021, at the level requested in its adjusted request. A settlement reached with the Tennessee Consumer Advocate in mid-January was approved by the TPUC on February 16, 2021. The settlement results in an increase of revenues of approximately $16 million and an ROE of 9.8%. Revised customer rates became effective on January 2, 2021. Piedmont refunded customers the difference between bills previously rendered under interim rates and such bills if rendered under approved rates, plus interest in April 2021.
2021 North Carolina Rate Case
On March 22, 2021, Piedmont filed an application with the NCUC for a rate increase for retail customers of approximately $109 million, which represents an approximate 10% increase in retail revenues. The rate increase is driven by customer growth and significant infrastructure upgrade investments (plant additions) since the last general rate case. Approximately 70% of the plant additions being rolled into rate base are categories of plant investment not covered under the IMR mechanism, which was originally approved as part of the 2013 North Carolina Rate Case. On July 28, 2021, Piedmont amended its requested increase to approximately $97 million.
On September 7, 2021, Piedmont and the Public Staff, the Carolina Utility Customers Association, Inc. and the Carolina Industrial Group for Fair Utility Rates IV filed a Stipulation of Partial Settlement (Stipulation), which is subject to review and approval by the NCUC, resolving most issues between these parties. Major components of the Stipulation include:
•A return on equity of 9.6% and a capital structure of 51.6% equity and 48.4% debt;
•Continuation of the IMR mechanism and margin decoupling; and
•A base rate increase of approximately $67 million, subject to completion of the Robeson County LNG facility and the Pender Onslow County expansion project.
An evidentiary hearing to review the Stipulation and other issues concluded on September 9, 2021. On October 12, 2021, Piedmont notified the NCUC of its intent to implement the stipulated rates effective November 1, 2021, on a temporary basis and subject to refund. On October 18, 2021, Piedmont and the Public Staff filed supplemental testimony attesting to the completion of the Robeson County LNG facility and the Pender Onslow County expansion project and to the propriety of including the capital investment for these two projects in this proceeding. On January 6, 2022, the NCUC issued an order approving the Stipulation. No refunds need to be rendered to customers arising from Piedmont's implementation of interim rates.
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 in June 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 of 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, 2021, there is $47 million and $53 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 $100 million to satisfy remaining ARO requirements to restore construction sites.
See Notes 7 and 12 for additional information regarding this transaction.
Potential Coal Plant Retirements
The Subsidiary Registrants periodically file integrated resource plans (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 lives. 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 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, 2021, and exclude capitalized asset retirement costs.
Remaining Net
CapacityBook Value
(in MW)(in millions)
Duke Energy Carolinas
Allen Steam Station Unit 1(a)
167 $12 
Allen Steam Station Unit 5(b)
259 277 
Cliffside Unit 5(b)
546 365 
Duke Energy Progress
Mayo Unit 1(b)
713 631 
Roxboro Units 3-4(b)
1,409 457 
Duke Energy Florida
Crystal River Units 4-5(c)
1,442 1,650 
Duke Energy Indiana(d)
Gibson Units 1-5(e)
2,845 1,829 
Cayuga Units 1-2(e)
1,005 696 
Total Duke Energy8,386 $5,917 
(a)    As part of the 2015 resolution of a lawsuit involving alleged New Source Review violations, Duke Energy Carolinas must retire Allen Steam Station Units 1 through 3 by December 31, 2024. The long-term energy options considered in the IRP could result in retirement of these units earlier than their current estimated useful lives. Unit 3 with a capacity of 270 MW and a net book value of $26 million at December 31, 2020, was retired in March 2021, and unit 2 with a capacity of 167 MW and a net book value of $44 million at December 31, 2020, was retired in December 2021.
(b)    These units were included in the IRP filed by Duke Energy Carolinas and Duke Energy Progress in North Carolina and South Carolina on September 1, 2020. The long-term energy options considered in the IRP could result in retirement of these units earlier than their current estimated useful lives. In 2019, Duke Energy Carolinas and Duke Energy Progress filed North Carolina rate cases that included depreciation studies that accelerate end-of-life dates for these plants. The NCUC issued orders in the 2019 rate cases of Duke Energy Carolinas and Duke Energy Progress on March 31, 2021, and April 16, 2021, respectively, in which the proposals to shorten the remaining depreciable lives of these units were denied, while indicating the IRP proceeding was the appropriate proceeding for the review of generating plant retirements. Allen Unit 4 with a capacity of 267 MW and a net book value of $170 million at December 31, 2020, was retired in December 2021.
(c)    On January 14, 2021, Duke Energy Florida filed the 2021 Settlement 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.
(d)    Gallagher Units 2 and 4 with a total capacity of 280 MW and a total net book value of $102 million at December 31, 2020, were retired on June 1, 2021.
(e)    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.