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Regulatory Matters | 12 Months Ended
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Dec. 31, 2019
Regulated Operations [Abstract] |
Regulatory Matters | REGULATORY MATTERS REGULATORY ASSETS AND LIABILITIES The Duke Energy Registrants record regulatory assets and liabilities that result from the ratemaking process. See Note 1 for further information. The following tables present the regulatory assets and liabilities recorded on the Consolidated Balance Sheets of Duke Energy and Progress Energy. See separate tables below for balances by individual registrant.
| Duke Energy |  | Progress Energy
| December 31, |  | December 31,
(in millions) | 2019 |  |  | 2018 |  |  | 2019 |  |  | 2018 |
Regulatory Assets |  |  |  |  |  |  |
AROs – coal ash | $ | 4,084 |  |  | $ | 4,255 |  |  | $ | 1,843 |  |  | $ | 2,061 |
AROs – nuclear and other | 739 |  |  | 772 |  |  | 668 |  |  | 601 |
Accrued pension and OPEB | 2,391 |  |  | 2,654 |  |  | 897 |  |  | 1,074 |
Storm cost deferrals | 1,399 |  |  | 1,117 |  |  | 1,214 |  |  | 953 |
Nuclear asset securitized balance, net | 1,042 |  |  | 1,093 |  |  | 1,042 |  |  | 1,093 |
Debt fair value adjustment | 1,019 |  |  | 1,099 |  |  | — |  |  | — |
Deferred fuel and purchased power | 528 |  |  | 838 |  |  | 305 |  |  | 600 |
Deferred asset – Lee and Harris COLA | 388 |  |  | 426 |  |  | 38 |  |  | 43 |
Hedge costs deferrals | 356 |  |  | 204 |  |  | 129 |  |  | 74 |
Demand side management (DSM)/Energy Efficiency (EE) | 343 |  |  | 449 |  |  | 241 |  |  | 256 |
Advanced metering infrastructure (AMI) | 338 |  |  | 367 |  |  | 114 |  |  | 127 |
Retired generation facilities | 331 |  |  | 402 |  |  | 266 |  |  | 324 |
Post-in-service carrying costs (PISCC) and deferred operating expenses | 329 |  |  | 320 |  |  | 33 |  |  | 36 |
Vacation accrual | 214 |  |  | 213 |  |  | 41 |  |  | 41 |
Derivatives – natural gas supply contracts | 117 |  |  | 141 |  |  | — |  |  | — |
Nuclear deferral | 107 |  |  | 133 |  |  | 40 |  |  | 46 |
Manufactured gas plant (MGP) | 102 |  |  | 99 |  |  | — |  |  | — |
Deferred pipeline integrity costs | 79 |  |  | 65 |  |  | — |  |  | — |
NCEMPA deferrals | 72 |  |  | 50 |  |  | 72 |  |  | 50 |
East Bend deferrals | 44 |  |  | 47 |  |  | — |  |  | — |
Transmission expansion obligation | 36 |  |  | 39 |  |  | — |  |  | — |
Amounts due from customers | 36 |  |  | 24 |  |  | — |  |  | — |
Grid modernization | 28 |  |  | 31 |  |  | — |  |  | — |
Other | 896 |  |  | 784 |  |  | 349 |  |  | 322 |
Total regulatory assets | 15,018 |  |  | 15,622 |  |  | 7,292 |  |  | 7,701 |
Less: current portion | 1,796 |  |  | 2,005 |  |  | 946 |  |  | 1,137 |
Total noncurrent regulatory assets | $ | 13,222 |  |  | $ | 13,617 |  |  | $ | 6,346 |  |  | $ | 6,564 |
Regulatory Liabilities |  |  |  |  |  |  |
Net regulatory liability related to income taxes | $ | 7,872 |  |  | $ | 8,058 |  |  | $ | 2,595 |  |  | $ | 2,710 |
Costs of removal | 5,756 |  |  | 5,421 |  |  | 2,561 |  |  | 2,135 |
AROs – nuclear and other | 1,100 |  |  | 538 |  |  | — |  |  | — |
Accrued pension and OPEB | 176 |  |  | 301 |  |  | — |  |  | 149 |
Amounts to be refunded to customers | 34 |  |  | 34 |  |  | — |  |  | — |
Deferred fuel and purchased power | 1 |  |  | 16 |  |  | 1 |  |  | 16 |
Other | 1,109 |  |  | 1,064 |  |  | 398 |  |  | 319 |
Total regulatory liabilities | 16,048 |  |  | 15,432 |  |  | 5,555 |  |  | 5,329 |
Less: current portion | 784 |  |  | 598 |  |  | 330 |  |  | 280 |
Total noncurrent regulatory liabilities | $ | 15,264 |  |  | $ | 14,834 |  |  | $ | 5,225 |  |  | $ | 5,049 |
Descriptions of regulatory assets and liabilities summarized in the tables above and below follow. See tables below for recovery and amortization periods at the separate registrants. AROs – coal ash. Represents deferred depreciation and accretion related to the legal obligation to close ash basins. The costs are deferred until recovery treatment has been determined. See Notes 1 and 10 for additional information. AROs – nuclear and other. Represents regulatory assets or liabilities, including deferred depreciation and accretion, related to legal obligations associated with the future retirement of property, plant and equipment, excluding amounts related to coal ash. The AROs relate primarily to decommissioning nuclear power facilities. The amounts also include certain deferred gains and losses on NDTF investments. See Notes 1 and 10 for additional information. Accrued pension and OPEB. Accrued pension and OPEB represent regulatory assets and liabilities related to each of the Duke Energy Registrants’ respective shares of unrecognized actuarial gains and losses and unrecognized prior service cost and credit attributable to Duke Energy’s pension plans and OPEB plans. The regulatory asset or liability is amortized with the recognition of actuarial gains and losses and prior service cost and credit to net periodic benefit costs for pension and OPEB plans. The accrued pension and OPEB regulatory assets are expected to be recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail. Storm cost deferrals. Represents deferred incremental costs incurred related to major weather-related events. 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. Deferred fuel and purchased power. Represents certain energy-related costs that are recoverable or refundable as approved by the applicable regulatory body. Deferred asset – Lee and Harris COLA. Represents deferred costs incurred for the canceled Lee and Harris nuclear projects. Hedge costs and other deferrals. Amounts relate to unrealized gains and losses on derivatives recorded as a regulatory asset or liability, respectively, until the contracts are settled. DSM/EE. Deferred costs related to various DSM and EE programs recoverable through various mechanisms. 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 expected future recovery of net book value of electromechanical meters that have been replaced with AMI meters at Duke Energy Indiana. 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. Vacation accrual. Represents vacation entitlement, which is generally recovered in the following year. Derivatives – natural gas supply contracts. Represents costs for certain long-dated, fixed quantity forward gas supply contracts, which are recoverable through PGA clauses. 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. 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. Deferred pipeline integrity costs. Represents pipeline integrity management costs in compliance with federal regulations recovered through a rider mechanism. NCEMPA deferrals. Represents retail allocated cost deferrals and returns associated with the additional ownership interest in assets acquired from NCEMPA in 2015. East Bend deferrals. Represents both deferred operating expenses and deferred depreciation as well as carrying costs on the portion of East Bend that was acquired from Dayton Power and Light and that had been previously operated as a jointly owned facility. Transmission expansion obligation. Represents transmission expansion obligations related to Duke Energy Ohio’s withdrawal from MISO. Amounts due from customers. Relates primarily to margin decoupling and IMR recovery mechanisms. Grid modernization. Amounts represent 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. Net regulatory liability related to income taxes. Amounts for all registrants include regulatory liabilities related primarily to impacts from the Tax Act. See Note 24 for additional information. Amounts have no immediate impact on rate base as regulatory assets are offset by deferred tax liabilities. Costs of removal. Represents funds received from customers to cover the future removal of property, plant and equipment from retired or abandoned sites as property is retired. Also includes certain deferred gains on NDTF investments. 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, 2019. 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, 2019. Duke Energy Carolinas Duke Energy Carolinas must limit cumulative distributions subsequent to mergers to (i) the amount of retained earnings on the day prior to the closing of the mergers, plus (ii) any future earnings recorded. Duke Energy Progress Duke Energy Progress must limit cumulative distributions subsequent to the mergers between Duke Energy and Progress Energy and Duke Energy and Piedmont to (i) the amount of retained earnings on the day prior to the closing of the respective mergers, plus (ii) any future earnings recorded. Duke Energy Ohio Duke Energy Ohio will not declare and pay dividends out of capital or unearned surplus without the prior authorization of the PUCO. Duke Energy Ohio received FERC and PUCO approval to pay dividends from its equity accounts that are reflective of the amount that it would have in its retained earnings account had push-down accounting for the Cinergy merger not been applied to Duke Energy Ohio’s balance sheet. The conditions include a commitment from Duke Energy Ohio that equity, adjusted to remove the impacts of push-down accounting, will not fall below 30% of total capital. Duke Energy Kentucky is required to pay dividends solely out of retained earnings and to maintain a minimum of 35% equity in its capital structure. Duke Energy Indiana Duke Energy Indiana must limit cumulative distributions subsequent to the merger between Duke Energy and Cinergy to (i) the amount of retained earnings on the day prior to the closing of the merger, plus (ii) any future earnings recorded. In addition, Duke Energy Indiana will not declare and pay dividends out of capital or unearned surplus without prior authorization of the IURC. Piedmont Piedmont must limit cumulative distributions subsequent to the acquisition of Piedmont by Duke Energy to (i) the amount of retained earnings on the day prior to the closing of the merger, plus (ii) any future earnings recorded. RATE-RELATED INFORMATION The NCUC, PSCSC, FPSC, IURC, PUCO, TPUC and KPSC approve rates for retail electric and natural gas services within their states. The FERC approves rates for electric sales to wholesale customers served under cost-based rates (excluding Ohio and Indiana), as well as sales of transmission service. The FERC also regulates certification and siting of new interstate natural gas pipeline projects. Duke Energy Carolinas and Duke Energy Progress Hurricane Florence, Hurricane Michael and Winter Storm Diego Deferral Filings On December 21, 2018, Duke Energy Carolinas and Duke Energy Progress filed with the NCUC petitions for approval to defer the incremental costs incurred in connection with the response to Hurricane Florence, Hurricane Michael and Winter Storm Diego to a regulatory asset for recovery in the next base rate case. The NCUC issued an order requesting comments on the deferral positions. On March 5, 2019, the North Carolina Public Staff (Public Staff) filed comments. On April 2, 2019, Duke Energy Carolinas and Duke Energy Progress filed reply comments, which included revised estimates of approximately $553 million in incremental operation and maintenance expenses ($171 million and $382 million for Duke Energy Carolinas and Duke Energy Progress, respectively) and approximately $96 million in capital costs ($20 million and $76 million for Duke Energy Carolinas and Duke Energy Progress, respectively). On September 30, 2019, Duke Energy Carolinas requested that the NCUC consolidate its pending deferral request with its general rate case filed on that date. On October 30, 2019, Duke Energy Progress requested that the NCUC consolidate its pending deferral request with its general rate case filed on that date. Duke Energy Carolinas and Duke Energy Progress cannot predict the outcome of these matters. Duke Energy Progress filed a deferral request for these storms with the PSCSC on January 11, 2019, which also included a request for the continuation of prior deferrals requested for ice storms and Hurricane Matthew, and on January 30, 2019, the PSCSC issued a directive approving the deferral request, followed by an order issued on February 21, 2019. On March 15, 2019, Duke Energy Progress filed a request with FERC requesting permission to defer transmission-related storm costs that would be charged to wholesale transmission customers through Duke Energy Progress' Open Access Transmission Tariff (OATT) and to recover those costs from wholesale transmission customers over a three-year recovery period. FERC accepted the filing on May 14, 2019, which allows Duke Energy Progress to proceed with the proposed cost deferral and recovery. Duke Energy Carolinas Regulatory Assets and Liabilities The following tables present the regulatory assets and liabilities recorded on Duke Energy Carolinas' Consolidated Balance Sheets.
| December 31, |  | Earns/Pays | Recovery/Refund
(in millions) | 2019 |  | 2018 |  |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
AROs – coal ash | $ | 1,696 |  | $ | 1,725 |  |  | (i) | (b)
Accrued pension and OPEB | 477 |  | 581 |  |  |  | (j)
Storm cost deferrals | 178 |  | 160 |  |  | Yes | (b)
Deferred fuel and purchased power | 222 |  | 196 |  |  | (f) | 2021
Deferred asset – Lee COLA | 350 |  | 383 |  |  |  | (b)
Hedge costs deferrals(c) | 198 |  | 101 |  |  | Yes | 2041
DSM/EE | 100 |  | 169 |  |  | (h) | (h)
AMI | 166 |  | 176 |  |  | Yes | (b)
Retired generation facilities(c) | 16 |  | 21 |  |  | Yes | 2023
PISCC(c) | 33 |  | 34 |  |  | Yes | (b)
Vacation accrual | 80 |  | 78 |  |  | (e) | 2020
Nuclear deferral | 67 |  | 87 |  |  |  | 2021
Other | 327 |  | 266 |  |  |  | (b)
Total regulatory assets | 3,910 |  | 3,977 |  |  |  |
Less: current portion | 550 |  | 520 |  |  |  |
Total noncurrent regulatory assets | $ | 3,360 |  | $ | 3,457 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
Net regulatory liability related to income taxes(d) | $ | 3,060 |  | $ | 3,082 |  |  |  | (b)
Costs of removal(c) | 1,936 |  | 1,968 |  |  | Yes | (g)
AROs – nuclear and other | 1,100 |  | 538 |  |  |  | (b)
Accrued pension and OPEB | 39 |  | 38 |  |  |  | (j)
Other | 543 |  | 572 |  |  |  | (b)
Total regulatory liabilities | 6,678 |  | 6,198 |  |  |  |
Less: current portion | 255 |  | 199 |  |  |  |
Total noncurrent regulatory liabilities | $ | 6,423 |  | $ | 5,999 |  |  |  |
(a) | Regulatory assets and liabilities are excluded from rate base unless otherwise noted.
(b) | The expected recovery or refund period varies or has not been determined.
(c) | Included in rate base.
(d) | Includes regulatory liabilities related to the change in the federal tax rate as a result of the Tax Act and the change in the North Carolina tax rate, both discussed in Note 24.
(e) | Earns a return on outstanding balance in North Carolina.
(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) | Recovered over the life of the associated assets.
(h) | Includes incentives on DSM/EE investments and is recovered through an annual rider mechanism.
(i) | Earns a debt and equity return on coal ash expenditures for North Carolina and South Carolina retail customers as permitted by various regulatory orders.
(j) | Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail.
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, which represented an approximate 13.6% increase in annual base revenues. The request for rate increase was driven by capital investments subsequent to the previous base rate case, including the W.S. Lee CC, grid improvement projects, AMI, investments in customer service technologies, costs of complying with CCR regulations and the Coal Ash Act and recovery of costs related to licensing and development of the William States Lee III Nuclear Station. 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 a return on equity of 9.9% and a capital structure of 52% equity and 48% debt. As a result of the settlement, Duke Energy Carolinas recorded a pretax charge of approximately $4 million in the first quarter of 2018 to Operation, maintenance and other on the Consolidated Statements of Operations. On June 22, 2018, the NCUC issued an order approving the Stipulation of Partial Settlement and requiring a revenue reduction. As a result of the June 22, 2018, order, Duke Energy Carolinas recorded a pretax charge of approximately $150 million to Impairment charges and Operation, maintenance and other on the Consolidated Statements of Operations. The charge was primarily related to the denial of a return on the Lee Nuclear Project and the assessment of a $70 million management penalty by reducing the annual recovery of deferred coal ash costs by $14 million per year over a five-year recovery period. On July 27, 2018, NCUC approved Duke Energy Carolinas' compliance filing. As a result, revised customer rates were effective on August 1, 2018. On July 20, 2018, the North Carolina Attorney General filed a Notice of Appeal to the North Carolina Supreme Court from the June 22, 2018, Order Accepting Stipulation, Deciding Contested Issues and Requiring Revenue Reduction issued by the NCUC. The Attorney General contends the commission’s order should be reversed and remanded, as it is in excess of the commission’s statutory authority; affected by errors of law; unsupported by competent, material and substantial evidence in view of the entire record as submitted; and arbitrary or capricious. The Sierra Club, North Carolina Sustainable Energy Association, North Carolina Justice Center, North Carolina Housing Coalition, Natural Resource Defense Council and Southern Alliance for Clean Energy also filed Notices of Appeal to the North Carolina Supreme Court. On August 8, 2018, the Public Staff filed a Notice of Cross Appeal to the North Carolina Supreme Court, which contends the commission’s June 22, 2018, order should be reversed and remanded, as it is affected by errors of law, and is unsupported by substantial evidence with regard to the commission’s failure to consider substantial evidence of coal ash related environmental violations. On November 29, 2018, the North Carolina Attorney General's Office filed a motion with the North Carolina Supreme Court requesting the court consolidate the Duke Energy Carolinas and Duke Energy Progress appeals and enter an order adopting the parties’ proposed briefing schedule as set out in the filing. On November 29, 2018, the North Carolina Supreme Court adopted a schedule for briefing set forth in the motion to consolidate the Duke Energy Carolinas and Duke Energy Progress appeals. Appellant briefs were filed on April 26, 2019. The Appellee response briefs were filed on September 25, 2019. Oral arguments before the North Carolina Supreme Court are scheduled for March 11, 2020. Duke Energy Carolinas cannot predict the outcome of this matter. 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 represents an approximate 6% increase in annual base revenues. The gross rate case revenue increase request is $445 million, which is 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 rate increase is 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 requests rates be effective no later than August 1, 2020. The NCUC has established a procedural schedule with an evidentiary hearing to commence on March 23, 2020. Duke Energy Carolinas cannot predict the outcome of this matter. 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, which represents an approximate 10% increase in retail revenues. The request for rate increase was driven by capital investments and environmental compliance progress made by Duke Energy Carolinas since its previous rate case, including the further implementation of Duke Energy Carolinas’ generation modernization program, which consists of retiring, replacing and upgrading generation plants, investments in customer service technologies and continued investments in base work to maintain its transmission and distribution systems. The request included net tax benefits resulting from the Tax Act of $66 million to reflect the change in ongoing tax expense, primarily from the reduction in the federal income tax rate from 35% to 21%. The request also included $46 million to return EDIT resulting from the federal tax rate change and deferred revenues since January 2018 related to the change and benefits of $17 million from a reduction in North Carolina state income taxes allocable to South Carolina (EDIT Rider). Duke Energy Carolinas also requested approval of its proposed Grid Improvement Plan (GIP), adjustments to its Prepaid Advantage Program and a variety of accounting orders related to ongoing costs for environmental compliance, including recovery over a five-year period of $242 million of deferred coal ash related compliance costs, grid investments between rate changes, incremental depreciation expense, a result of new depreciation rates from the depreciation study approved in the 2017 North Carolina Rate Case above, and the balance of development costs associated with the cancellation of the Lee Nuclear Project. Finally, Duke Energy Carolinas sought approval to establish a reserve and accrual for end-of-life nuclear costs for nuclear fuel and materials and supplies. On March 8, 2019, the ORS moved to establish a new and separate hearing docket to review and consider the GIP proposed by Duke Energy Carolinas. Subsequently, on March 12, 2019, the ORS and Duke Energy Carolinas executed a Stipulation resolving the ORS’s motion. The Stipulation provided that costs incurred for the GIP after January 1, 2019, would be deferred with a return, subject to evaluation in a future rate proceeding. The Stipulation was approved by the PSCSC on June 19, 2019. On December 16, 2019, Duke Energy Carolinas and Duke Energy Progress filed a Joint Petition to Establish an Informational Docket for Review and Consideration of Grid Improvement Plans through which Duke Energy Carolinas and Duke Energy Progress would provide interested stakeholders information on the companies' grid activities. The PSCSC requested parties comment on procedural matters by January 31; accordingly, various groups filed comments, none of which opposed an informational docket. Duke Energy Carolinas cannot predict the outcome of this matter. After hearings in March 2019, the PSCSC issued an order on May 21, 2019, which included a return on equity 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 commission 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, return on equity 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 South Carolina Supreme Court. On November 20, 2019, the South Carolina Energy Users Committee filed a Notice of Appeal and the ORS filed a Notice of Cross Appeal with the South Carolina Supreme Court. On January 8, 2020, Duke Energy Carolinas and the ORS filed a joint motion to extend briefing schedule deadlines. Appellant briefs are due on March 2, 2020, and Appellee response briefs are due on May 15, 2020. On February 12, 2020, Duke Energy Carolinas and the ORS filed a joint motion to extend briefing deadlines by 30 days. Based on legal analysis and the filing of the appeal, Duke Energy Carolinas has not recorded an adjustment for its deferred coal ash costs. Duke Energy Carolinas cannot predict the outcome of this matter. FERC Formula Rate Matter On July 31, 2017, PMPA filed a complaint with FERC alleging that Duke Energy Carolinas misapplied the formula rate under the PPA between the parties by including in its rates amortization expense associated with regulatory assets and recorded in a certain account without FERC approval. On February 15, 2018, FERC issued an order ruling in favor of PMPA and ordered Duke Energy Carolinas to refund to PMPA all amounts improperly collected under the PPA. Duke Energy Carolinas has issued to PMPA and similarly situated wholesale customers refunds of approximately $25 million. FERC also set the matter for settlement and hearing. PMPA and other customers filed a protest to Duke Energy Carolinas' refund report claiming that the refunds are inadequate in that (1) Duke Energy Carolinas invoked the limitations periods in the contracts to limit the time period for which the refunds were paid and the customers disagree that this limitation applies, and (2) Duke Energy Carolinas refunded only amounts recovered through a certain account and the customers have asserted that the order applies to all regulatory assets. On July 3, 2018, FERC issued an order accepting Duke Energy Carolinas' refund report and ruling that these two claims are outside the scope of FERC's February order. The settlement agreements and revised formula rates for all parties to the proceeding were filed on December 28, 2018. On April 2, 2019, FERC issued an order approving the settlement agreement as filed. Since then, Duke Energy Carolinas has implemented the terms of the settlement in rates with all wholesale customers, including non-intervening customers. On July 25, 2019, Duke Energy Carolinas received FERC approval for the accounting treatment requested for certain assets included in the settlement agreements. This is the final approval needed from FERC and concludes this proceeding. Sale of Hydroelectric (Hydro) Plants In May 2018, Duke Energy Carolinas entered an agreement for the sale of five hydro plants with a combined 18.7-MW generation capacity in the Western Carolinas region to Northbrook Energy. The completion of the transaction was subject to approval from FERC for the four FERC-licensed plants, as well as other state regulatory agencies and was contingent upon regulatory approval from the NCUC and PSCSC to defer the total estimated loss on the sale of approximately $40 million. On July 5, 2018, Duke Energy Carolinas filed with the NCUC for approval of the sale of the five hydro plants to Northbrook, to transfer the CPCNs for the four North Carolina hydro plants and to establish a regulatory asset for the North Carolina retail portion of the difference between sales proceeds and net book value. On June 5, 2019, the NCUC issued an order approving the transfer of the hydro plants from Duke Energy Carolinas to Northbrook, granting deferral accounting and denying the Public Staff's motion for reconsideration. On August 28, 2018, Duke Energy Carolinas filed with PSCSC an Application for Approval of Transfer and Sale of Hydroelectric Generation Facilities, Acceptance for Filing of a Power Purchase Agreement and an Accounting Order to Establish a Regulatory Asset. On September 10, 2018, the ORS provided a letter to the commission stating its position on the application and on September 18, 2018, Duke Energy Carolinas requested this matter be carried over to allow Duke Energy Carolinas time to discuss certain accounting issues with the ORS. At its June 26, 2019, agenda meeting, the PSCSC voted to approve the transfer and sale subject to the recommendation of the ORS that the issuance of an Accounting Order will not preclude the ORS, the commission or any other party from addressing the reasonableness of these costs, any return sought and including any carrying costs in the next rate case. On August 9, 2018, Duke Energy Carolinas and Northbrook filed a joint Application for Transfer of Licenses with the FERC. On December 27, 2018, the FERC issued its Order Approving Transfer of Licenses for the four FERC-licensed hydro plants. On January 18, 2019, Duke Energy Carolinas and Northbrook Carolina Hydro II, LLC requested a six-month extension of time to comply with the requirement of the December 27, 2018, order that Northbrook submit to FERC certified copies of all instruments of conveyance and signed acceptance sheets within 60 days of the date of the order. On February 14, 2019, FERC issued an order granting extensions until August 26, 2019, to comply with the requirements of the December 27, 2018, order. The closing occurred on August 16, 2019. A regulatory asset was established for approximately $32 million, which represents the total deferral amount for North Carolina and South Carolina retail. The North Carolina retail portion will be amortized pursuant to an order from the NCUC. Duke Energy Carolinas will purchase all the capacity and energy generated by these facilities at the avoided cost for five years through power purchase agreements. Duke Energy Progress Regulatory Assets and Liabilities The following tables present the regulatory assets and liabilities recorded on Duke Energy Progress' Consolidated Balance Sheets.
| December 31, |  | Earns/Pays | Recovery/Refund
(in millions) | 2019 |  | 2018 |  |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
AROs – coal ash | $ | 1,834 |  | $ | 2,051 |  |  | (h) | (b)
AROs – nuclear and other | 509 |  | 429 |  |  |  | (c)
Accrued pension and OPEB | 423 |  | 542 |  |  |  | (k)
Storm cost deferrals(d) | 801 |  | 571 |  |  | Yes | (b)
Deferred fuel and purchased power | 266 |  | 397 |  |  | (f) | 2021
Deferred asset – Harris COLA | 38 |  | 43 |  |  |  |
Hedge costs deferrals | 85 |  | 54 |  |  |  | (b)
DSM/EE(e) | 216 |  | 235 |  |  | (i) | (i)
AMI | 61 |  | 67 |  |  |  | (b)
Retired generation facilities | 83 |  | 105 |  |  | Yes | (b)
PISCC and deferred operating expenses | 33 |  | 36 |  |  | Yes | 2054
Vacation accrual | 41 |  | 41 |  |  |  | 2020
Nuclear deferral | 40 |  | 46 |  |  |  | 2021
NCEMPA deferrals | 72 |  | 50 |  |  | (g) | 2042
Other | 176 |  | 147 |  |  |  | (b)
Total regulatory assets | 4,678 |  | 4,814 |  |  |  |
Less: current portion | 526 |  | 703 |  |  |  |
Total noncurrent regulatory assets | $ | 4,152 |  | $ | 4,111 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
Net regulatory liability related to income taxes(l) | $ | 1,802 |  | $ | 1,863 |  |  |  | (b)
Costs of removal | 2,294 |  | 1,878 |  |  | Yes | (j)
Accrued pension and OPEB | — |  | 93 |  |  |  | (k)
Other | 372 |  | 299 |  |  |  | (b)
Total regulatory liabilities | 4,468 |  | 4,133 |  |  |  |
Less: current portion | 236 |  | 178 |  |  |  |
Total noncurrent regulatory liabilities | $ | 4,232 |  | $ | 3,955 |  |  |  |
(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 23 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.
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 represented an approximate 14.9% increase in annual base revenues. Subsequent to the filing, Duke Energy Progress adjusted the requested amount to $420 million, representing an approximate 13% increase. The request for rate increase was driven by capital investments subsequent to the previous base rate case, costs of complying with CCR regulations and the Coal Ash Act, costs relating to storm recovery, investments in customer service technologies and recovery of costs associated with renewable purchased power. 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 a return on equity 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 order also impacted certain amounts that were similarly recorded on Duke Energy Carolinas' Consolidated Balance Sheets. As a result of the order, Duke Energy Progress and Duke Energy Carolinas recorded pretax charges of $68 million and $14 million, respectively, in the first quarter of 2018 to Impairment charges, Operation, maintenance and other and Interest Expense on the Consolidated Statements of Operations. Revised customer rates became effective on March 16, 2018. On May 15, 2018, the Public Staff filed a Notice of Cross Appeal to the North Carolina Supreme Court from the NCUC's February 23, 2018, order. The Public Staff contends the NCUC’s order should be reversed and remanded, as it is affected by errors of law, and is unsupported by competent, material and substantial evidence in view of the entire record as submitted. The North Carolina Attorney General and Sierra Club also filed Notices of Appeal to the North Carolina Supreme Court from the February 23, 2018, order. On November 29, 2018, the North Carolina Attorney General's Office filed a motion with the North Carolina Supreme Court requesting the court consolidate the Duke Energy Progress and Duke Energy Carolinas appeals and enter an order adopting the parties’ proposed briefing schedule as set out in the filing. Appellant briefs were filed on April 26, 2019. The Appellee response briefs were filed on September 25, 2019. Oral arguments before the North Carolina Supreme Court are scheduled for March 11, 2020. Duke Energy Progress cannot predict the outcome of this matter. 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 represents an approximate 12.3% increase in annual base revenues. The gross rate case revenue increase request is $586 million, which is 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 rate increase is 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 seeks to defer and recover incremental Hurricane Dorian storm costs in this proceeding and requests rates be effective no later than September 1, 2020. The NCUC has established a procedural schedule with an evidentiary hearing to commence on May 4, 2020. Duke Energy Progress cannot predict the outcome of this matter. Hurricane Dorian Hurricane Dorian reached the Carolinas in September 2019 as a Category 2 hurricane making landfall within Duke Energy Progress’ service territory. Approximately 270,000 North Carolina customers and 30,000 South Carolina customers were impacted by the slow-moving storm that brought high winds, tornadoes and heavy rain. With storm-response mobilization occurring in preparation for the storm and the assistance of mutual aid partners, full restoration was accomplished within four days for all customers able to receive service. Total estimated incremental operation and maintenance expenses incurred to repair and restore the system are approximately $205 million with an additional $4 million in capital investments made for restoration efforts. Approximately $179 million of the operation and maintenance expenses are deferred in Regulatory assets within Other Noncurrent Assets on the Consolidated Balance Sheets as of December 31, 2019. The balance of operation and maintenance expenses are included in Operation, maintenance and other on the Consolidated Statements of Operations for the year ended December 31, 2019. A request for an accounting order to defer incremental storm costs associated with Hurricane Dorian was included in Duke Energy Progress' October 30, 2019, general rate case filing with the NCUC. Duke Energy Progress cannot predict the outcome of this matter. 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, which represents an approximate 10.3% increase in annual base revenues. The request for rate increase was driven by capital investments and environmental compliance progress made by Duke Energy Progress since its previous rate case, including the further implementation of Duke Energy Progress’ generation modernization program, which consists of retiring, replacing and upgrading generation plants, investments in customer service technologies and continued investments in base work to maintain its transmission and distribution systems. The request included a decrease resulting from the Tax Act of $17 million to reflect the change in ongoing tax expense, primarily the reduction in the federal income tax rate from 35% to 21%. The request also included $10 million to return EDIT resulting from the federal tax rate change and deferred revenues since January 2018 related to the change (EDIT Rider) and a $12 million increase due to the expiration of EDITs related to reductions in North Carolina state income taxes allocable to South Carolina. Duke Energy Progress also requested approval of its proposed GIP, approval of a Prepaid Advantage Program and a variety of accounting orders related to ongoing costs for environmental compliance, including recovery over a five-year period of $51 million of deferred coal ash related compliance costs, AMI deployment, grid investments between rate changes and regulatory asset treatment related to the retirement of a generating plant located in Asheville, North Carolina. Finally, Duke Energy Progress sought approval to establish a reserve and accrual for end-of-life nuclear costs for materials and supplies and nuclear fuel. On March 8, 2019, the ORS moved to establish a new and separate hearing docket to review and consider the GIP proposed by Duke Energy Progress. Subsequently, on March 12, 2019, the ORS and Duke Energy Carolinas executed a Stipulation resolving the ORS’s motion, and Duke Energy Progress agreed to the Stipulation, as did other parties in the rate case. The Stipulation provides that costs incurred for the GIP after January 1, 2019, would be deferred with a return, with all costs subject to evaluation in a future rate proceeding. The Stipulation was approved by the PSCSC on June 19, 2019. On December 16, 2019, Duke Energy Progress and Duke Energy Carolinas filed a Joint Petition to Establish an Informational Docket for Review and Consideration of Grid Improvement Plans through which Duke Energy Progress and Duke Energy Carolinas would provide interested stakeholders information on the companies' grid activities. The PSCSC requested parties comment on procedural matters by January 31; accordingly, various groups filed comments, none of which opposed an informational docket. Duke Energy Progress cannot predict the outcome of this matter. After hearings in April 2019, the PSCSC issued an order on May 21, 2019, which included a return on equity 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 commission 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, return on equity 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. Duke Energy Progress filed a notice of appeal on November 15, 2019, with the South Carolina Supreme Court. The ORS filed a Notice of Cross Appeal on November 20, 2019. On January 8, 2020, Duke Energy Progress and the ORS filed a joint motion to extend briefing schedule deadlines. Appellant briefs are due on March 2, 2020, and Appellee response briefs are on May 15, 2020. On February 12, 2020, Duke Energy Progress and the ORS filed a joint motion to extend briefing deadlines by 30 days. Based on legal analysis and the filing of the appeal, Duke Energy Progress has not recorded an adjustment for its deferred coal ash costs. Duke Energy Progress cannot predict the outcome of this matter. Western Carolinas Modernization Plan On November 4, 2015, Duke Energy Progress announced a Western Carolinas Modernization Plan, which included retirement of the existing Asheville coal-fired plant, the construction of two 280 MW combined-cycle natural gas plants having dual-fuel capability, with the option to build a third natural gas simple cycle unit in 2023 based upon the outcome of initiatives to reduce the region's power demand. The plan also included upgrades to existing transmission lines and substations, installation of solar generation and a pilot battery storage project. Duke Energy Progress worked with the local natural gas distribution company to upgrade and lease an existing natural gas pipeline to serve the natural gas plant. The lease for the new pipeline became effective on March 2, 2019. On March 28, 2016, the NCUC issued an order approving a CPCN for the new combined-cycle natural gas plants, but is requiring Duke Energy Progress to refile for CPCN approval for the contingent simple cycle unit. On March 28, 2019, Duke Energy Progress filed an annual progress report for the construction of the combined-cycle plants with the NCUC, with an estimated cost of $893 million. On December 27, 2019, Asheville Combined Cycle Power Block 1 and the common systems that serve both combined cycle units went into commercial operation. Power Block 1 consists of the Unit 5 Combustion Turbine and Unit 6 Steam Turbine Generator (which together form the first combined cycle unit approved in the CPCN Order). Power Block 2 consists of the Unit 7 Combustion Turbine and Unit 8 Steam Turbine Generator (which together form the second combined cycle unit approved in the CPCN Order). Duke Energy Progress placed the Unit 7 Combustion Turbine portion of Power Block 2 into commercial operation in simple-cycle mode on January 15, 2020. Duke Energy Progress currently expects to place the Unit 8 Steam Turbine Generator into commercial operation in the first quarter of 2020, after final testing has been completed. On October 8, 2018, Duke Energy Progress filed an application with the NCUC for a CPCN to construct the Hot Springs Microgrid Solar and Battery Storage Facility. On March 22, 2019, Duke Energy Progress and the Public Staff filed a Joint Proposed Order. On May 10, 2019, the NCUC issued an Order Granting Certificate of Public Convenience and Necessity with Conditions. On November 19, 2019, Duke Energy Progress filed a semiannual progress report for its Hot Springs Microgrid Solar and Battery Storage Facility. As required by an NCUC order issued December 6, 2019, an updated progress report was filed on January 15, 2020. Construction is expected to begin in March 2020 with commercial operation expected to begin in September 2020. The carrying value of the 376-MW Asheville coal-fired plant, including associated ash basin closure costs, of $214 million and $327 million is included in Generation facilities to be retired, net on Duke Energy Progress' Consolidated Balance Sheets as of December 31, 2019, and 2018, respectively. Duke Energy Progress' request for a regulatory asset at the time of retirement with amortization over a 10-year period was approved by the NCUC on February 23, 2018. Duke Energy Progress retired the Asheville coal-fired plant on January 29, 2020. FERC Return on Equity Complaint On October 11, 2019, NCEMPA filed a complaint at FERC against Duke Energy Progress pursuant to Section 206 of the Federal Power Act (FPA). The complaint alleges that the return on equity component in the formula rate contained within the Full Requirements Power Purchase Agreement (FRPPA) is unjust and unreasonable. The FRPPA’s return on equity is 11% as applied to the Production Capacity Rate for the full requirements service provided by Duke Energy Progress. The complaint does not definitively propose a replacement return on equity. Under FPA Section 206, the earliest refund effective date that FERC can establish is the date of the filing of the complaint. The complaint could raise risks across the Duke Energy Progress wholesale business because, depending on how FERC treats NCEMPA's complaint, other parties may come forward with similar complaints. 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/Pays | Recovery/Refund
(in millions) | 2019 |  | 2018 |  |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
AROs – coal ash(c) | $ | 9 |  | $ | 10 |  |  |  | (b)
AROs – nuclear and other(c) | 159 |  | 172 |  |  |  | (b)
Accrued pension and OPEB(c) | 474 |  | 532 |  |  | Yes | (g)
Storm cost deferrals(c) | 413 |  | 382 |  |  | (e) | 2021
Nuclear asset securitized balance, net | 1,042 |  | 1,093 |  |  |  | 2036
Deferred fuel and purchased power | 39 |  | 203 |  |  | (f) | 2021
Hedge costs deferrals | 44 |  | 20 |  |  |  | 2038
DSM/EE(c) | 25 |  | 21 |  |  | Yes | 2024
AMI(c) | 53 |  | 60 |  |  | Yes | 2032
Retired generation facilities(c) | 183 |  | 219 |  |  | Yes | (b)
Other | 172 |  | 176 |  |  | (d) | (b)
Total regulatory assets | 2,613 |  | 2,888 |  |  |  |
Less: current portion | 419 |  | 434 |  |  |  |
Total noncurrent regulatory assets | $ | 2,194 |  | $ | 2,454 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
Net regulatory liability related to income taxes(c) | $ | 793 |  | $ | 847 |  |  |  | (b)
Costs of removal(c) | 267 |  | 257 |  |  | (d) | (b)
Accrued pension and OPEB | — |  | 56 |  |  | Yes | (g)
Deferred fuel and purchased power(c) | 1 |  | 16 |  |  | (f) | 2021
Other | 26 |  | 20 |  |  | (d) | (b)
Total regulatory liabilities | 1,087 |  | 1,196 |  |  |  |
Less: current portion | 94 |  | 102 |  |  |  |
Total noncurrent regulatory liabilities | $ | 993 |  | $ | 1,094 |  |  |  |
(a) | Regulatory assets and liabilities are excluded from rate base unless otherwise noted.
(b) | The expected recovery or refund period varies or has not been determined.
(c) | Included in rate base.
(d) | Certain costs earn/pay a return.
(e) | Earns a debt return/interest once collections begin.
(f) | Earns commercial paper rate.
(g) | Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail.
Storm Restoration Cost Recovery In September 2017, Duke Energy Florida’s service territory suffered significant damage from Hurricane Irma, resulting in approximately 1 million customers experiencing outages. In the fourth quarter of 2017, Duke Energy Florida also incurred preparation costs related to Hurricane Nate. On December 28, 2017, Duke Energy Florida filed a petition with the FPSC to recover incremental storm restoration costs for Hurricane Irma and Hurricane Nate and to replenish the storm reserve. On February 6, 2018, the FPSC approved a stipulation that would apply tax savings resulting from the Tax Act toward storm costs effective January 2018 in lieu of implementing a storm surcharge. On May 31, 2018, Duke Energy Florida filed a petition for approval of actual storm restoration costs and associated recovery process related to Hurricane Irma and Hurricane Nate. The petition sought the approval for the recovery in the amount of $510 million in actual recoverable storm restoration costs, including the replenishment of Duke Energy Florida’s storm reserve of $132 million, and the process for recovering these recoverable storm costs. On August 20, 2018, the FPSC approved Duke Energy Florida's unopposed Motion for Continuance filed August 17, 2018, to allow for an evidentiary hearing in this matter. On January 28, 2019, Duke Energy Florida made a supplemental filing to reduce the total storm cost recovery from $510 million to $508 million. On April 3, 2019, the FPSC issued an Order abating all remaining filing dates. On April 9, 2019, Duke Energy Florida filed an unopposed motion to approve a settlement agreement resolving all outstanding issues in this docket. On June 13, 2019, the FPSC issued its order approving the settlement agreement. The Storm Cost Settlement Agreement obligates Duke Energy Florida to capitalize $18 million of storm costs and remove $6 million of operating and maintenance expense, thereby reducing the requested storm cost recovery amount by $24 million. Duke Energy Florida will also implement process changes with respect to storm cost restoration. At December 31, 2019, and December 31, 2018, Duke Energy Florida's Consolidated Balance Sheets included approximately $43 million and $217 million, respectively, of recoverable costs under the FPSC's storm rule in Regulatory assets within Current Assets and Other Noncurrent Assets related to storm recovery for Hurricane Irma and Hurricane Nate. In October 2018, Duke Energy Florida’s service territory suffered damage when Hurricane Michael made landfall as a Category 5 hurricane with maximum sustained winds of 160 mph. The storm caused catastrophic damage from wind and storm surge, particularly from Panama City Beach to Mexico Beach, resulting in widespread outages and significant damage to transmission and distribution facilities across the central Florida Panhandle. In response to Hurricane Michael, Duke Energy Florida restored service to approximately 72,000 customers. Total estimated incremental operation and maintenance and capital costs are $311 million. Approximately $107 million and $35 million of the costs are included in Net property, plant and equipment on the Consolidated Balance Sheets as of December 31, 2019, and December 31, 2018, respectively. Approximately $204 million and $165 million of costs are included in Regulatory assets within Current Assets and Other Noncurrent Assets on the Consolidated Balance Sheets as of December 31, 2019, and December 31, 2018, respectively, representing recoverable costs under the FPSC’s storm rule and Duke Energy Florida's OATT formula rates. Duke Energy Florida filed a petition with the FPSC on April 30, 2019, to recover the retail portion of incremental storm restoration costs for Hurricane Michael. On June 11, 2019, the FPSC approved the petition for recovery of incremental storm restoration costs related to Hurricane Michael. The FPSC also approved the stipulation Duke Energy Florida filed, which will allow 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 are currently expected to be fully recovered by approximately 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. An Order Establishing Procedure was issued on January 30, 2020, and hearings are scheduled to begin September 15, 2020. Duke Energy Florida cannot predict the outcome of this matter. Hurricane Dorian In September 2019, Duke Energy Florida’s service territory was threatened by Hurricane Dorian with landfall as a possible Category 5 hurricane. For several days, various forecasts and models predicted significant impact to Duke Energy Florida’s service territory; accordingly, Duke Energy Florida incurred costs to secure necessary resources to be prepared for that potential impact. Although Hurricane Dorian never made landfall in Florida, its effects were still felt, and outages did occur. Preparations were required so that, if Hurricane Dorian had made landfall and impacts had been more severe, Duke Energy Florida would have been prepared to restore its customers’ power in a timely fashion. Total current estimated incremental costs are approximately $167 million. These costs are included in Regulatory assets within Current Assets and Other Noncurrent Assets on the Consolidated Balance Sheets as of December 31, 2019, representing recoverable costs under the FPSC’s storm rule and Duke Energy Florida's OATT formula rates. On December 19, 2019, Duke Energy Florida filed a petition with the FPSC to recover the estimated retail portion of these costs, consistent with the provisions in the 2017 Settlement. The request seeks recovery over a 12-month period beginning in March 2020. The final actual amount will be filed later in 2020 and a hearing will be held at the FPSC to determine the final amount of incremental costs. Duke Energy Florida cannot predict the outcome of this matter. Tax Act Pursuant to Duke Energy Florida's 2017 Settlement, on May 31, 2018, Duke Energy Florida filed a petition related to the Tax Act, which included revenue requirement impacts of annual tax savings of $134 million and estimated annual amortization of EDIT of $67 million for a total of $201 million. Of this amount, $50 million would be offset by accelerated depreciation of Crystal River 4 and 5 coal units and an estimated $151 million would be offset by Hurricane Irma storm cost recovery as explained in the Storm Restoration Cost Recovery section above. On December 27, 2018, Duke Energy Florida filed actual EDIT balances and amortization based on its 2017 filed tax return. This increased the revenue requirement impact of the amortization of EDIT by $4 million, from $67 million to $71 million, which increased the total storm amortization from $151 million to $155 million. On January 8, 2019, the FPSC approved a joint motion by Duke Energy Florida and the Office of Public Counsel resolving all stipulated positions. As part of that stipulation, Duke Energy Florida agreed to seek a Private Letter Ruling (PLR) from the IRS on its treatment of cost of removal (COR) as mostly protected by tax normalization rules. If the IRS rules that COR is not protected by tax normalization rules, then Duke Energy Florida will make a final adjustment to the amortization of EDIT and an adjustment to the storm recovery amount retroactive to January 2018. The IRS has communicated that it will not issue individual PLRs on the treatment of COR. Rather, the IRS is drafting a notice that will request comments on a number of issues, including COR, and the IRS plans to issue industrywide guidance on those issues. Duke Energy Florida cannot predict the outcome of this matter. Citrus County CC Construction of the 1,640-MW combined-cycle natural gas plant in Citrus County, Florida, began in October 2015 with an estimated cost of $1.5 billion, including AFUDC. Both units came on-line in the fourth quarter of 2018. The ultimate cost of the facility was estimated to be $1.6 billion, and Duke Energy Florida recorded Impairment charges on Duke Energy’s Consolidated Statements of Operations of $60 million in the fourth quarter of 2018 for the overrun. In the year ended December 31, 2019, Duke Energy Florida recorded a $36 million reduction to the prior-year impairment due to a decrease in the cost estimate of the Citrus County CC, primarily related to the settlement agreement with Fluor, the EPC contractor. This adjustment reduced the estimated cost of the facility to $1.5 billion. Solar Base Rate Adjustment On July 31, 2018, Duke Energy Florida petitioned the FPSC to include in base rates the revenue requirements for its first two solar generation projects, the Hamilton Project and the Columbia Project, as authorized by the 2017 Settlement. The Hamilton Project, which was placed into service on December 22, 2018, has an annual retail revenue requirement of $15 million. At its October 30, 2018, Agenda Conference, the FPSC approved the rate increase related to the Hamilton Project to go into effect beginning with the first billing cycle in January 2019 under its file and suspend authority, and revised customer rates became effective in January 2019. The Columbia Project has a projected annual revenue requirement of $14 million and a projected in-service date in early 2020; the associated rate increase would take place with the first month’s billing cycle after the Columbia Project goes into service. On April 2, 2019, the commission approved both solar projects as filed. On March 25, 2019, Duke Energy Florida petitioned the FPSC to include in base rates the revenue requirements for its next wave of solar generation projects, the Trenton, Lake Placid and DeBary Solar Projects, as authorized by the 2017 Settlement. The annual retail revenue requirement for the Trenton and Lake Placid Projects is $13 million and $8 million, respectively, and were placed into service in December 2019 with rates taking effect in January 2020. The DeBary Project has a projected annual revenue requirement of $11 million and a projected in-service date in the first half of 2020. The associated rate increase would take place with the first month’s billing cycle after each solar generation project goes into service. On July 22, 2019, the FPSC issued an order approving Duke Energy Florida's request. Crystal River Unit 3 Accelerated Decommissioning Filing On May 29, 2019, Duke Energy Florida entered into a Decommissioning Services Agreement for the accelerated decommissioning of the Crystal River Unit 3 nuclear power station located in Citrus County, Florida, with ADP CR3, LLC and ADP SF1, LLC, each of which is a wholly owned subsidiary of Accelerated Decommissioning Partners, LLC, a joint venture between NorthStar Group Services, Inc. and Orano USA LLC. Closing of this agreement is contingent upon the approval of the NRC and FPSC. If approved, the decommissioning will be accelerated starting in 2020 and continuing through 2027, rather than the expected time frame under SAFSTOR of starting in 2067 and ending in 2074. Duke Energy Florida expects that the assets of the Nuclear Decommissioning Trust Fund will be sufficient to cover the contract price. On July 10, 2019, Duke Energy Florida petitioned the FPSC for approval of the agreement. Duke Energy Florida cannot predict the outcome of this matter. Duke Energy Ohio Regulatory Assets and Liabilities The following tables present the regulatory assets and liabilities recorded on Duke Energy Ohio's Consolidated Balance Sheets.
| December 31, |  | Earns/Pays | Recovery/Refund
(in millions) | 2019 |  | 2018 |  |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
AROs – coal ash | $ | 16 |  | $ | 20 |  |  | Yes | (b)
Accrued pension and OPEB | 155 |  | 146 |  |  |  | (g)
Storm cost deferrals | 7 |  | 4 |  |  |  | 2023
Deferred fuel and purchased power | 1 |  | 2 |  |  |  | 2020
Hedge costs deferrals | 6 |  | 5 |  |  |  | (b)
DSM/EE | 2 |  | 10 |  |  | (f) | (e)
AMI | 40 |  | 46 |  |  |  | (b)
PISCC and deferred operating expenses(c) | 17 |  | 17 |  |  | Yes | 2083
Vacation accrual | 5 |  | 5 |  |  |  | 2020
MGP | 102 |  | 99 |  |  |  | (b)
Deferred pipeline integrity costs | 17 |  | 14 |  |  | Yes | (b)
East Bend deferrals | 44 |  | 47 |  |  | Yes | (b)
Transmission expansion obligation | 40 |  | 43 |  |  |  | (e)
Grid modernization | 28 |  | 31 |  |  | Yes | (b) (c)
Other | 118 |  | 75 |  |  |  | (b)
Total regulatory assets | 598 |  | 564 |  |  |  |
Less: current portion | 49 |  | 33 |  |  |  |
Total noncurrent regulatory assets | $ | 549 |  | $ | 531 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
Net regulatory liability related to income taxes | $ | 654 |  | $ | 678 |  |  |  | (b)
Costs of removal | 86 |  | 126 |  |  |  | (d)
Accrued pension and OPEB | 16 |  | 18 |  |  |  | (g)
Other | 71 |  | 75 |  |  |  | (b)
Total regulatory liabilities | 827 |  | 897 |  |  |  |
Less: current portion | 64 |  | 57 |  |  |  |
Total noncurrent regulatory liabilities | $ | 763 |  | $ | 840 |  |  |  |
(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 23 for additional detail.
2017 Electric Security Plan Filing On June 1, 2017, Duke Energy Ohio filed with the PUCO a request for a standard service offer in the form of an Electric Security Plan (ESP). On February 15, 2018, the procedural schedule was suspended to facilitate ongoing settlement discussions. On April 13, 2018, Duke Energy Ohio filed a Motion to consolidate this proceeding with several other cases pending before the PUCO, including, but not limited to, its Electric Base Rate Case. Additionally, on April 13, 2018, Duke Energy Ohio, along with certain intervenors, filed a Stipulation and Recommendation (Stipulation) with the PUCO resolving certain issues in this proceeding. The term of the ESP would be from June 1, 2018, to May 31, 2025, and included continuation of market-based customer rates through competitive procurement processes for generation, continuation and expansion of existing rider mechanisms and proposed new rider mechanisms relating to regulatory mandates, costs incurred to enhance the customer experience and transform the grid and a service reliability rider for vegetation management. The Stipulation established a regulatory model for the next seven years via the approval of the ESP and continued the current model for procuring supply for non-shopping customers, including recovery mechanisms. On December 19, 2018, the PUCO approved the Stipulation without material modification. Several parties, including the OCC, filed applications for rehearing. On February 6, 2019, the PUCO granted the parties rehearing. The PUCO issued its Second Entry on Rehearing on July 17, 2019, upholding its December 19, 2018, order and denying all assignments of error raised by the non-stipulating parties. On October 11, 2019, the OCC filed its Third Application for Rehearing arguing the PUCO erred in finding OCC’s Second Application for Rehearing as improper. Duke Energy Ohio filed its Memorandum Contra on October 21, 2019. The PUCO denied OCC's Third Application for Rehearing as a matter of law. On September 13, 2019, Interstate Gas Supply/Retail Supply Association filed appeals to the Ohio Supreme Court claiming the PUCO’s order was in error because it approved unsupported charges to competitive suppliers and cost subsidies shopping customers pay for non-shopping customers. On September 16, 2019, the OCC filed an appeal challenging the PUCO’s approval of OVEC recovery through Rider PSR alleging the FPA pre-empts the commission’s jurisdiction and that the record does not support finding that Rider PSR results in a limitation on shopping. Appellant briefs were filed on January 6, 2020. Appellee briefs will be due March 16, 2020. Duke Energy Ohio cannot predict the outcome of this matter. Electric Base Rate Case Duke Energy Ohio filed with the PUCO an electric distribution base rate case application and supporting testimony in March 2017. Duke Energy Ohio requested an estimated annual increase of approximately $15 million and a return on equity of 10.4%. The application also included requests to continue certain current riders and establish new riders. On September 26, 2017, the PUCO staff filed a report recommending a revenue decrease between approximately $18 million and $29 million and a return on equity between 9.22% and 10.24%. On April 13, 2018, Duke Energy Ohio filed a Motion to consolidate this proceeding with several other cases pending before the PUCO. On April 13, 2018, Duke Energy Ohio, along with certain intervenors, filed the Stipulation with the PUCO resolving numerous issues including those in this base rate proceeding. Major components of the Stipulation related to the base distribution rate case included a $19 million decrease in annual base distribution revenue with a return on equity unchanged from the current rate of 9.84% based upon a capital structure of 50.75% equity and 49.25% debt. Upon approval of new rates, Duke Energy Ohio's rider for recovering its initial SmartGrid implementation ended as these costs would be recovered through base rates. The Stipulation also renewed 14 existing riders, some of which were included in the company's ESP, and added two new riders including the Enhanced Service Reliability Rider to recover vegetation management costs not included in base rates, up to $10 million per year (operation and maintenance only) and the PowerForward Rider to recover costs incurred to enhance the customer experience and further transform the grid (operation and maintenance and capital). In addition to the changes in revenue attributable to the Stipulation, Duke Energy Ohio’s capital-related riders, including the Distribution Capital Investments Rider, began to reflect the lower federal income tax rate associated with the Tax Act with updates to customers’ bills beginning April 1, 2018. This change reduced electric revenue by approximately $20 million on an annualized basis. On December 19, 2018, the PUCO approved the Stipulation without material modification. New base rates were implemented effective January 2, 2019. Several parties including the OCC filed applications for rehearing. On February 6, 2019, the PUCO granted the parties rehearing. The PUCO issued its Second Entry on Rehearing on July 17, 2019, upholding its December 19, 2018, order and denying all assignments of error raised by the non-stipulating parties. On October 11, 2019, the OCC filed its Third Application for Rehearing arguing the PUCO erred in finding OCC’s Second Application for Rehearing as improper. Duke Energy Ohio filed its Memorandum Contra on October 21, 2019. The PUCO denied OCC's Third Application for Rehearing as a matter of law. On September 13, 2019, Interstate Gas Supply/Retail Supply Association filed appeals to the Ohio Supreme Court claiming the PUCO’s order was in error because it approved unsupported charges to competitive suppliers and cost subsidies shopping customers pay for non-shopping customers. On September 16, 2019, the OCC filed an appeal challenging the PUCO’s approval of OVEC recovery through Rider PSR alleging the FPA pre-empts the commission’s jurisdiction and that the record does not support finding that Rider PSR results in a limitation on shopping. Appellant briefs were filed on January 6, 2020. Appellee briefs will be due March 16, 2020. Duke Energy Ohio cannot predict the outcome of this matter. Ohio Valley Electric Corporation On March 31, 2017, Duke Energy Ohio filed for approval to adjust its existing Rider PSR to pass through net costs related to its contractual entitlement to capacity and energy from the generating assets owned by OVEC. Duke Energy Ohio sought deferral authority for net costs incurred from April 1, 2017, until the new rates under Rider PSR were put into effect. On April 13, 2018, Duke Energy Ohio filed a Motion to consolidate this proceeding with several other cases currently pending before the PUCO. Also, on April 13, 2018, Duke Energy Ohio, along with certain intervenors, filed a Stipulation with the PUCO resolving numerous issues including those related to Rider PSR. The Stipulation activated Rider PSR for recovery of net costs incurred from January 1, 2018, through May 2025. On December 19, 2018, the PUCO approved the Stipulation without material modification. The PSR rider became effective April 1, 2019. Several parties, including the OCC, filed applications for rehearing. On February 6, 2019, the PUCO granted the parties rehearing. The PUCO issued its Second Entry on Rehearing on July 17, 2019, upholding its December 19, 2018, order and denying all assignments of error raised by the non-stipulating parties. On October 11, 2019, the OCC filed its Third Application for Rehearing arguing the PUCO erred in finding OCC’s Second Application for Rehearing as improper. Duke Energy Ohio filed its Memorandum Contra on October 21, 2019. The PUCO denied OCC's Third Application for Rehearing as a matter of law. On September 13, 2019, Interstate Gas Supply/Retail Supply Association filed appeals to the Ohio Supreme Court claiming the PUCO’s order was in error because it approved unsupported charges to competitive suppliers and cost subsidies shopping customers pay for non-shopping customers. On September 16, 2019, the OCC filed an appeal challenging the PUCO’s approval of OVEC recovery through Rider PSR alleging the FPA pre-empts the commission’s jurisdiction and that the record does not support finding that Rider PSR results in a limitation on shopping. Appellant briefs were filed on January 6, 2020. Appellee briefs will be due March 16, 2020. Duke Energy Ohio cannot predict the outcome of this matter. On July 23, 2019, an Ohio bill was signed into law that became effective January 1, 2020. Among other things, the bill allows for recovery of prudently incurred costs, net of any revenues, for Ohio investor-owned utilities that are participants under the OVEC power agreement. The recovery shall be through a non-bypassable rider that is to replace any existing recovery mechanism approved by the PUCO and will remain in place through 2030. The amounts recoverable from customers will be subject to an annual cap, with incremental costs that exceed such cap eligible for deferral and recovery subject to review. See Note 18 for additional discussion of Duke Energy Ohio's ownership interest in OVEC. Tax Act – Ohio On July 25, 2018, Duke Energy Ohio filed an application to establish a new rider to implement the benefits of the Tax Act for electric distribution customers. The new rider will flow through to customers the benefit of the lower 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. Duke Energy Ohio's transmission rates reflect lower federal income tax but guidance from FERC on amortization of both protected and unprotected transmission-related EDITs is still pending. On October 24, 2018, the PUCO issued a Finding and Order that, among other things, directed all utilities over which the commission has ratemaking authority to file an application to pass the benefits of the Tax Act to customers by January 1, 2019, unless otherwise exempted or directed by the PUCO. Duke Energy Ohio's July 25, 2018, filing for electric distribution operations is consistent with the commission's October 24, 2018, Finding and Order and no further action is needed. On February 20, 2019, the PUCO approved the application without material modification. Rates became effective March 1, 2019. On December 21, 2018, Duke Energy Ohio filed an application to change its base rates 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 changes and rider effective April 1, 2019. The new rider will flow through to customers the benefit of the lower 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. Duke Energy Ohio cannot predict the outcome of this matter. Energy Efficiency Cost Recovery On March 28, 2014, Duke Energy Ohio filed an application for recovery of program costs, lost distribution revenue and performance incentives related to its energy efficiency and peak demand reduction programs. These programs are undertaken to comply with environmental mandates set forth in Ohio law. The PUCO approved Duke Energy Ohio’s application but found that Duke Energy Ohio was not permitted to use banked energy savings from previous years in order to calculate the amount of allowed incentive. This conclusion represented a change to the cost recovery mechanism that had been agreed upon by intervenors and approved by the PUCO in previous cases. The PUCO granted the applications for rehearing filed by Duke Energy Ohio and an intervenor. On January 6, 2016, Duke Energy Ohio and the PUCO Staff entered into a stipulation, pending the PUCO's approval, to resolve issues related to performance incentives and the PUCO Staff audit of 2013 costs, among other issues. In December 2015, based upon the stipulation, Duke Energy Ohio re-established approximately $20 million of the revenues that had been previously reversed. On October 26, 2016, the PUCO issued an order approving the stipulation without modification. In December 2016, the PUCO granted the intervenors request for rehearing for the purpose of further review. On April 10, 2019, the PUCO issued an Entry on Rehearing denying the rehearing applications. On June 15, 2016, Duke Energy Ohio filed an application for approval of a three-year energy efficiency and peak demand reduction portfolio of programs. A stipulation and modified stipulation were filed on December 22, 2016, and January 27, 2017, respectively. Under the terms of the stipulations, which included support for deferral authority of all costs and a cap on shared savings incentives, Duke Energy Ohio has offered its energy efficiency and peak demand reduction programs throughout 2017. On February 3, 2017, Duke Energy Ohio filed for deferral authority of its costs incurred in 2017 in respect of its proposed energy efficiency and peak demand reduction portfolio. On September 27, 2017, the PUCO issued an order approving a modified stipulation. The modifications impose an annual cap of approximately $38 million on program costs and shared savings incentives combined, but allowed for Duke Energy Ohio to file for a waiver of costs in excess of the cap in 2017. The PUCO approved the waiver request for 2017 up to a total cost of $56 million. On November 21, 2017, the PUCO granted Duke Energy Ohio's and intervenor's applications for rehearing of the September 27, 2017, order. On January 10, 2018, the PUCO denied the OCC's application for rehearing of the PUCO order granting Duke Energy Ohio's waiver request; however, a decision on Duke Energy Ohio's application for rehearing remains pending. On October 15, 2019, the Ohio Supreme Court issued an Opinion regarding a similar cap on energy efficiency imposed by the PUCO on Ohio Edison Company finding the PUCO lacked statutory authority to impose a cap on cost recovery. On December 9, 2019, and in response to recent changes to Ohio Law, the OCC filed a motion to eliminate shared savings from Duke Energy Ohio’s energy efficiency calculation beginning in 2020. Duke Energy Ohio filed a memorandum contra and a notice of additional authority on December 16, 2019, arguing OCC’s interpretation is incorrect and that the commission should amend its September 27, 2017 order to comply with recent precedent. Duke Energy Ohio cannot predict the outcome of this matter. 2014 Electric Security Plan On May 30, 2018, the PUCO approved an extension of Duke Energy Ohio’s then-current ESP, including all terms and conditions thereof, excluding an extension of Duke Energy Ohio’s Distribution Capital Investment Rider. Following rehearing, on July 25, 2018, the PUCO granted the request and allowed a continuing cap on recovery under Rider DCI. The orders were upheld on rehearing requested by the Ohio Manufacturers' Association (OMA) and OCC. The time period for parties to file for rehearing or appeal has expired. In 2018, the OMA and OCC filed separate appeals of PUCO's approval of Duke Energy Ohio’s ESP with the Ohio Supreme Court, challenging PUCO's approval of Duke Energy Ohio’s Rider PSR as a placeholder and its Rider DCI to recover incremental revenue requirement for distribution capital since Duke Energy Ohio’s last base rate case. The Ohio Supreme Court issued an order on March 13, 2019, for the appellants to show cause why the appeals should not be dismissed as moot in light of the commission’s approval of Duke Energy Ohio’s current ESP. The OCC and OMA made the requested filings on March 20, 2019, and Duke Energy Ohio filed its response on March 27, 2019. Subsequent to OCC and OMA making the requested filings, the Ohio Supreme Court dismissed the appeals as moot on May 8, 2019. Natural Gas Pipeline Extension Duke Energy Ohio is proposing to install 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 $163 million to $245 million in direct costs (excluding overheads and AFUDC). On January 20, 2017, Duke Energy Ohio filed an amended application with the Ohio Power Siting Board (OPSB) for approval of one of two proposed routes. A public hearing was held on June 15, 2017. In April 2018, Duke Energy Ohio filed a motion with OPSB to establish a procedural schedule and filed supplemental information supporting its application. On December 18, 2018, the OPSB established a procedural schedule that included a local public hearing on March 21, 2019. An evidentiary hearing began on April 9, 2019, and concluded on April 11, 2019. Briefs were filed on May 13, 2019, and reply briefs were filed on June 10, 2019. On November 21, 2019, the 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. Duke Energy Ohio filed a memorandum contra on January 2, 2020. On January 17, 2020, the OPSB granted rehearing for the purpose of further consideration. Construction of the pipeline extension is expected to be completed before the 2021/2022 winter season. Duke Energy Ohio cannot predict the outcome of this matter. 2012 Natural Gas Rate Case/MGP Cost Recovery As part of its 2012 natural gas base rate case, Duke Energy Ohio has approval to defer and recover costs related to environmental remediation at two sites (East End and West End) that housed former MGP operations. Duke Energy Ohio has made annual applications for recovery of these deferred costs. Duke Energy Ohio has collected approximately $55 million in environmental remediation costs between 2009 through 2012 through a separate rider, 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 rate case. To date, the PUCO has not ruled on Duke Energy Ohio’s annual applications for the calendar years 2013 through 2017. On September 28, 2018, the staff of the PUCO issued a report recommending a disallowance of approximately $12 million of the $26 million in MGP remediation costs incurred between 2013 through 2017 that staff believes are not eligible for recovery. Staff interprets the PUCO’s 2012 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. To date, the PUCO has not ruled on Duke Energy Ohio’s applications. 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 staff believes occurred in areas not authorized for recovery. Additionally, 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 began on November 18, 2019, and concluded November 21, 2019. Initial briefs were filed on January 17, 2020, and reply briefs were filed on February 14, 2020. Duke Energy Ohio cannot predict the outcome of this matter. The 2012 PUCO order also contained conditional deadlines for completing the MGP environmental investigation and remediation costs at the MGP sites. 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 and investigation that must occur after December 31, 2019. 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. Duke Energy Ohio cannot predict the outcome of this matter. Duke Energy Kentucky Natural Gas Base Rate Case On August 31, 2018, Duke Energy Kentucky filed an application with the KPSC requesting an increase in natural gas base rates of approximately $11 million, an approximate 11.1% average increase across all customer classes. The increase was net of approximately $5 million in annual savings as a result of the Tax Act. The drivers for this case were capital invested since Duke Energy Kentucky’s last rate case in 2009. Duke Energy Kentucky also sought implementation of a Weather Normalization Adjustment Mechanism, amortization of regulatory assets and to implement the impacts of the Tax Act, prospectively. On January 30, 2019, Duke Energy Kentucky entered into a settlement agreement with the Attorney General of Kentucky, the only intervenor in the case. The settlement provided for an approximate $7 million increase in natural gas base revenue, a return on equity of 9.7% and approval of the proposed Weather Normalization Mechanism. A hearing was held on February 5, 2019. The commission issued its order approving the settlement without material modification on March 27, 2019. Revised customer rates were effective April 1, 2019. Duke Energy Kentucky Electric Base Rate Case On September 3, 2019, Duke Energy Kentucky filed a rate case with the KPSC requesting an increase in electric base rates of approximately $46 million, which represents an approximate 12.5% increase across all customer classes. The request for rate increase is driven by increased investment in utility plant since the last electric base rate case in 2017. Duke Energy Kentucky seeks to implement a Storm Deferral Mechanism that will enable Duke Energy Kentucky to defer actual costs incurred for major storms that are over or under amounts in base rates. In response to large customers’ desire to have access to renewable resources, Duke Energy Kentucky is proposing a Green Source Advantage tariff designed for those large customers that wish to invest in renewable energy resources to meet sustainability goals. Duke Energy Kentucky is proposing an electric vehicle (EV) infrastructure pilot and modest incentives to assist customers in investing in EV technologies. Additionally, Duke Energy Kentucky is proposing to build an approximate 3.4 MW distribution battery energy storage system to be attached to Duke Energy Kentucky’s distribution system providing frequency regulation and enhanced reliability to Kentucky customers. The commission issued a procedural schedule with two rounds of discovery and opportunities for intervenor and rebuttal testimony. The Kentucky Attorney General filed its testimony recommending an increase of approximately $26 million. On January 31, 2020, Duke Energy Kentucky filed rebuttal testimony updating its rate increase calculations to approximately $44 million. Hearings began on February 19, 2020. Duke Energy Kentucky anticipates that rates will go into effect in the second quarter of 2020. Duke Energy Kentucky 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, 2019, and 2018, $40 million and $43 million, respectively, are recorded in Regulatory assets on Duke Energy Ohio's Consolidated Balance Sheets.
|  |  | Provisions/ |  |  | Cash |  |  |
(in millions) | December 31, 2018 |  |  | Adjustments |  |  | Reductions |  |  | December 31, 2019 |
Duke Energy Ohio | $ | 58 |  |  | $ | — |  |  | $ | (4 | ) |  | $ | 54 |
Duke Energy Indiana Regulatory Assets and Liabilities The following tables present the regulatory assets and liabilities recorded on Duke Energy Indiana's Consolidated Balance Sheets.
| December 31, |  | Earns/Pays | Recovery/Refund
(in millions) | 2019 |  | 2018 |  |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
AROs – coal ash | $ | 529 |  | $ | 450 |  |  |  | (b)
Accrued pension and OPEB | 243 |  | 222 |  |  |  | (f)
Deferred fuel and purchased power | — |  | 40 |  |  |  | 2020
Hedge costs deferrals | 23 |  | 24 |  |  |  | (b)
DSM/EE | — |  | 14 |  |  | (e) | (e)
AMI(c) | 18 |  | 18 |  |  | Yes | (b)
Retired generation facilities(c) | 49 |  | 57 |  |  | Yes | 2026
PISCC and deferred operating expenses(c) | 246 |  | 233 |  |  | Yes | (b)
Vacation accrual | 12 |  | 11 |  |  |  | 2020
Other | 52 |  | 88 |  |  |  | (b)
Total regulatory assets | 1,172 |  | 1,157 |  |  |  |
Less: current portion | 90 |  | 175 |  |  |  |
Total noncurrent regulatory assets | $ | 1,082 |  | $ | 982 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
Net regulatory liability related to income taxes | $ | 1,008 |  | $ | 1,009 |  |  |  | (b)
Costs of removal | 599 |  | 628 |  |  |  | (d)
Accrued pension and OPEB | 90 |  | 67 |  |  |  | (f)
Amounts to be refunded to customers | — |  | 1 |  |  |  | 2020
Other | 43 |  | 42 |  |  |  | (b)
Total regulatory liabilities | 1,740 |  | 1,747 |  |  |  |
Less: current portion | 55 |  | 25 |  |  |  |
Total noncurrent regulatory liabilities | $ | 1,685 |  | $ | 1,722 |  |  |  |
(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) | Includes incentives on DSM/EE investments and is recovered through a tracker mechanism over a two-year period.
(f) | Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail.
2019 Indiana Rate Case On July 2, 2019, Duke Energy Indiana filed a general rate case with the IURC, its first general rate case in Indiana in 16 years, for a rate increase for retail customers of approximately $395 million. The request for rate increase is driven by strategic investments to generate cleaner electricity, improve reliability and serve a growing customer base. The request is premised upon a Duke Energy Indiana rate base of $10.2 billion as of December 31, 2018, and adjusted for projected changes through December 31, 2020. On September 9, 2019, Duke Energy Indiana revised its revenue request from $395 million to $393 million and filed updated testimony for the Retail Rate Case. The updated filing reflects a clarification in the presentation of Utility Receipts Tax, a $2 million reduction in the revenue requirement for revenues that will remain in riders and changes to allocation of revenue requirements within rate classes. The Utility Receipts Tax is currently embedded in base rates and rider rates. The proposed treatment is to include the Utility Receipts Tax as a line item on the customer bill rather than included in rates. The request is an approximate 15% increase in retail revenues and approximately 17% when including estimated Utility Receipts Tax. 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. The commission determined to take two issues out of the rate case and place them in separate subdocket proceedings due to the complexity of the rate case. The commission moved the request for electric transportation pilot and future coal ash recovery issues to separate subdockets. Coal ash expenditures prior to 2019 are still included in the rate case. Hearings concluded on February 7, 2020 and rates are expected to be effective by mid-2020. Duke Energy Indiana cannot predict the outcome of these matters. Edwardsport IGCC Plant On September 20, 2018, Duke Energy Indiana, the Indiana Office of Utility Consumer Counselor, the Duke Industrial Group and Nucor Steel – Indiana entered into a settlement agreement to resolve IGCC ratemaking issues for calendar years 2018 and 2019. The agreement will remain in effect until new rates are established in Duke Energy Indiana's next base rate case, which was filed on July 2, 2019, with rates to be effective in mid-2020. An evidentiary hearing was held in December 2018, and on June 5, 2019, the IURC issued an order approving the 2018 Settlement Agreement. Piedmont Regulatory Assets and Liabilities The following tables present the regulatory assets and liabilities recorded on Piedmont's Consolidated Balance Sheets.
| December 31, |  | Earns/Pays | Recovery/Refund
(in millions) | 2019 |  | 2018 |  |  | a Return | Period Ends
Regulatory Assets(a) |  |  |  |  |
AROs – nuclear and other | 16 |  | 19 |  |  |  | (d)
Accrued pension and OPEB(c) | 90 |  | 99 |  |  | Yes | (f)
Vacation accrual | 12 |  | 12 |  |  |  |
Derivatives – natural gas supply contracts(e) | 117 |  | 141 |  |  |  |
Deferred pipeline integrity costs(c) | 62 |  | 51 |  |  | Yes | (b)
Amounts due from customers | 36 |  | 24 |  |  | Yes | (b)
Other | 30 |  | 11 |  |  |  | (b)
Total regulatory assets | 363 |  | 357 |  |  |  |
Less: current portion | 73 |  | 54 |  |  |  |
Total noncurrent regulatory assets | $ | 290 |  | $ | 303 |  |  |  |
Regulatory Liabilities(a) |  |  |  |  |
Net regulatory liability related to income taxes | $ | 555 |  | $ | 579 |  |  |  | (b)
Costs of removal | 574 |  | 564 |  |  |  | (d)
Accrued pension and OPEB(c) | 3 |  | 1 |  |  | Yes | (f)
Amounts to be refunded to customers | 34 |  | 33 |  |  | Yes | (b)
Other | 46 |  | 41 |  |  |  | (b)
Total regulatory liabilities | 1,212 |  | 1,218 |  |  |  |
Less: current portion | 81 |  | 37 |  |  |  |
Total noncurrent regulatory liabilities | $ | 1,131 |  | $ | 1,181 |  |  |  |
(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) | Balance will fluctuate with changes in the market. Current contracts extend into 2031.
(f) | Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail.
North Carolina Integrity Management Rider Filing On April 30, 2019, Piedmont filed a petition under the IMR mechanism to update rates, based on the eligible capital investments closed to integrity and safety projects over the six-month period ending March 31, 2019. The NCUC approved the petition on May 29, 2019, and rates became effective June 1, 2019. The effect of the update was an increase to annual revenues of approximately $9 million. These revenues, along with eligible spending for the three months ended June 30, 2019, were subsequently included in base rates effective November 1, 2019, as part of the 2019 North Carolina Rate Case. On October 31, 2019, Piedmont filed a petition under the IMR mechanism to update rates, based on the eligible capital investments closed to integrity and safety projects over the three-month period ending September 30, 2019. The NCUC approved the petition on December 3, 2019, and rates became effective December 1, 2019. The effect of the update was an increase to annual revenues of approximately $11 million. Tennessee Integrity Management Rider Filing In November 2019, Piedmont filed a petition with the TPUC under the IMR mechanism to collect an additional $4 million in annual revenues, effective January 2020, based on the eligible capital spending on integrity and safety projects over the 12-month period ending October 31, 2019. A procedural schedule has not yet been set for this matter. Piedmont cannot predict the outcome of this matter. 2019 North Carolina Rate Case On April 1, 2019, Piedmont filed an application with the NCUC, its first general rate case in North Carolina in six years, for a rate increase for retail customers of approximately $83 million, which represents an approximate 9% increase in retail revenues. The request for rate increase was driven by significant infrastructure upgrade investments (plant additions) since the last general rate case through June 30, 2019, offset by savings that customers will begin receiving due to federal and state tax reform. Approximately half of the plant additions being included in 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 August 13, 2019, Piedmont, the Public Staff, and two groups representing industrial customers filed an Agreement and Stipulation Settlement resolving issues in the base rate proceeding, which included a return on equity of 9.7% and a capital structure of 52% equity and 48% debt. The North Carolina Attorney General's Office did not support the settlement. Other major components of the Stipulation included:
• | An annual increase in revenues of $109 million before consideration of riders associated with federal and state tax reform;
• | A decrease through a rider mechanism of $23 million per year to return unprotected federal EDIT over a five-year period and deferred revenues related to the federal rate reduction of $37 million to be returned over one year;
• | A decrease through a rider mechanism of $21 million per year related to reductions in the North Carolina state income tax rate to be returned over a three-year period;
• | An overall cap on net revenue increase of $83 million. This will impact Piedmont beginning November 1, 2022, only if the company does not file another general rate case in the interim;
• | Continuation of the IMR mechanism; and
• | Establishment of a new deferral mechanism for certain Distribution Integrity Management Program (DIMP) operations and maintenance expenses incurred effective November 1, 2019, and thereafter.
An evidentiary hearing began on August 19, 2019. On October 31, 2019, the NCUC approved the Stipulation and the revised customer rates were effective November 1, 2019. OTHER REGULATORY MATTERS Atlantic Coast Pipeline, LLC On September 2, 2014, Duke Energy, Dominion Energy, Inc. (Dominion), Piedmont and Southern Company Gas announced the formation of Atlantic Coast Pipeline, LLC (ACP) to build and own the proposed Atlantic Coast Pipeline (ACP pipeline), an approximately 600-mile interstate natural gas pipeline running from West Virginia to North Carolina. The ACP pipeline is designed to meet, in part, the needs identified by Duke Energy Carolinas, Duke Energy Progress and Piedmont. Dominion will be responsible for building and operating the ACP pipeline and holds a leading ownership percentage in ACP of 48%. Duke Energy owns a 47% interest, which is accounted for as an equity method investment through its Gas Utilities and Infrastructure segment. Southern Company Gas maintains a 5% interest. See Notes 13 and 18 for additional information related to Duke Energy's ownership interest. Duke Energy Carolinas, Duke Energy Progress and Piedmont, among others, will be customers of the pipeline. Purchases will be made under several 20-year supply contracts, subject to state regulatory approval. In 2018, the FERC issued a series of Notices to Proceed, which authorized the project to begin certain construction-related activities along the pipeline route, including supply header and compressors. On May 11, 2018, and October 19, 2018, FERC issued Notices to Proceed allowing full construction activities in all areas of West Virginia except in the Monongahela National Forest. On July 24, 2018, FERC issued a Notice to Proceed allowing full construction activities along the project route in North Carolina. On October 19, 2018, the conditions to effectiveness of the Virginia 401 water quality certification were satisfied and, following receipt of the Virginia 401 certification, ACP filed a request for FERC to issue a Notice to Proceed with full construction activities in Virginia. Due to legal challenges not directly related to the request for a Notice to Proceed in Virginia, this request is still pending. ACP is the subject of challenges in state and federal courts and agencies, including, among others, challenges of the project’s biological opinion (BiOp) and incidental take statement (ITS), crossings of the Blue Ridge Parkway, the Appalachian Trail, and the Monongahela and George Washington National Forests, the project’s U.S. Army Corps of Engineers (USACE) 404 permit, the project's air permit for a compressor station at Buckingham, Virginia, the FERC Environmental Impact Statement order and the FERC order approving the Certificate of Public Convenience and Necessity. Each of these challenges alleges non-compliance on the part of federal and state permitting authorities and adverse ecological consequences if the project is permitted to proceed. Since December 2018, notable developments in these challenges include a stay in December 2018 issued by the U.S. Court of Appeals for the Fourth Circuit (Fourth Circuit) and the same court's July 26, 2019, vacatur of the project's BiOp and ITS (which stay and subsequent vacatur halted most project construction activity), a Fourth Circuit decision vacating the project's permits to cross the Monongahela and George Washington National Forests and the Appalachian Trail, the Fourth Circuit's remand to USACE of ACP's Huntington District 404 verification, the Fourth Circuit’s remand to the National Park Service of ACP’s Blue Ridge Parkway right-of-way and the most recent vacatur of the air permit for a compressor station at Buckingham, Virginia. ACP is vigorously defending these challenges and coordinating with the federal and state authorities which are the direct parties to the challenges. The Solicitor General of the United States and ACP filed petitions for certiorari to the Supreme Court of the United States on June 25, 2019, regarding the Appalachian Trail crossing and certiorari was granted on October 4, 2019. The Supreme Court hearing is scheduled for February 24, 2020, and a ruling is expected in the second quarter of 2020. ACP is also evaluating possible legislative and other remedies to this issue. In anticipation of the Fourth Circuit's vacatur of the BiOp and ITS, ACP and the FWS commenced work in mid-May of 2019 to set the basis for a reissued BiOp and ITS. On February 10, 2020, FERC issued a letter to FWS requesting the re-initiation of formal consultation in support of reissuing the BiOp and ITS. ACP continues coordinating and working with FWS and other parties in preparation for a reissuance of the BiOp and ITS. ACP triggered the Adverse Government Actions (AGA) clause of its agreements with its customers in December 2019. Formal negotiations have commenced regarding pricing and construction timing, among other items, and are expected to be finalized in the first quarter of 2020. The results of these negotiations will directly impact the expected future cash flows of this project. Given the legal challenges and ongoing discussions with customers, ACP expects mechanical completion of the full project in late 2021 with in-service likely in the first half of 2022. The delays resulting from the legal challenges described above have also impacted the cost for the project. Project cost is approximately $8 billion, excluding financing costs. This estimate is based on the current facts available around construction costs and timelines, and is subject to future changes as those facts develop. Abnormal weather, work delays (including delays due to judicial or regulatory action) and other conditions may result in cost or schedule modifications, a suspension of AFUDC for ACP and/or impairment charges potentially material to Duke Energy's cash flows, financial position and results of operations. Duke Energy’s investment in ACP was $1.2 billion at December 31, 2019. Duke Energy evaluated this investment for impairment at December 31, 2019, and determined that fair value approximated carrying value and therefore no impairment was necessary. Duke Energy also has a guarantee agreement supporting its share of the ACP revolving credit facility. Duke Energy’s maximum exposure to loss under the terms of the guarantee is $827 million, which represents 47% of the outstanding borrowings under the credit facility as of December 31, 2019. See Note 13 for additional information. Constitution Pipeline Company, LLC Duke Energy owned a 24% ownership interest in Constitution, which is accounted for as an equity method investment. Constitution was a natural gas pipeline project slated to transport natural gas supplies from the Marcellus supply region in northern Pennsylvania to major northeastern markets. The pipeline was to be constructed and operated by Williams Partners L.P., which had a 41% ownership share. The remaining interest was held by Cabot Oil and Gas Corporation and WGL Holdings, Inc. In December 2014, Constitution received approval from the FERC to construct and operate the proposed pipeline. However, since April 2016, Constitution had stopped construction and discontinued capitalization of future development costs due to permitting delays and adverse rulings by regulatory agencies and courts. In late 2019, Constitution determined that its principal shipper would not agree to an amended precedent agreement. Without such an amendment, the project would no longer be viable and, as of February 5, 2020, the Constitution partners formally resolved to initiate the dissolution of Constitution, and to terminate the Constitution Pipeline project. In the fourth quarter of 2019, Duke Energy recorded an OTTI of $25 million related to Constitution within Equity in earnings of unconsolidated affiliates on Duke Energy's Consolidated Statements of Income, resulting in the full write-down of Duke Energy's investment in Constitution. See Notes 13 and 18 for additional information related to ownership interest and carrying value of the investment. Potential Coal Plant Retirements The Subsidiary Registrants periodically file IRPs with their state regulatory commissions. The IRPs provide a view of forecasted energy needs over a long term (10 to 20 years) and options being considered to meet those needs. IRPs filed by the Subsidiary Registrants included planning assumptions to potentially retire certain coal-fired generating facilities in North Carolina and Indiana earlier than their current estimated useful 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, 2019, and exclude capitalized asset retirement costs.
|  |  | Remaining Net |
| Capacity |  |  | Book Value |
| (in MW) |  |  | (in millions) |
Duke Energy Carolinas |  |  |
Allen Steam Station Units 1-3(a) | 585 |  |  | $ | 152 |
Duke Energy Indiana |  |  |
Gallagher Units 2 and 4(b) | 280 |  |  | 114 |
Gibson Units 1-5(c) | 3,132 |  |  | 1,697 |
Cayuga Units 1-2(c) | 1,005 |  |  | 974 |
Total Duke Energy | $ | 5,002 |  |  | $ | 2,937 |
(a) | Duke Energy Carolinas will retire Allen Steam Station Units 1 through 3 by December 31, 2024, as part of the resolution of a lawsuit involving alleged New Source Review violations.
(b) | Duke Energy Indiana committed to either retire or stop burning coal at Gallagher Units 2 and 4 by December 31, 2022, as part of the 2016 settlement of Edwardsport IGCC matters.
(c) | On July 1, 2019, Duke Energy Indiana filed its 2018 IRP with the IURC. The 2018 IRP included scenarios evaluating the potential retirement of coal-fired generating units at Gibson and Cayuga. The rate case filed July 2, 2019, includes proposed depreciation rates reflecting retirement dates from 2026 to 2038.
Duke Energy continues to evaluate the potential need to retire generating facilities earlier than the current estimated useful lives, and plans to seek regulatory recovery, as necessary, for amounts that would not be otherwise recovered when any of these assets are retired. However, such recovery, including recovery of carrying costs on remaining book values, could be subject to future approvals and therefore cannot be assured. Duke Energy Carolinas and Duke Energy Progress are evaluating the potential for coal-fired generating unit retirements with a net carrying value of approximately $721 million and $1.2 billion, respectively, included in Net property, plant and equipment on the Consolidated Balance Sheets as of December 31, 2019. Refer to the "Western Carolinas Modernization Plan" discussion above for details of Duke Energy Progress' planned retirements.

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