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Regulatory Matters

12 Months Ended

Dec. 31, 2024

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)	2024		2023		2024		2023
Regulatory Assets
AROs – coal ash	$	3,384	$	3,214	$	1,335	$	1,230
Accrued pension and OPEB	2,524		2,389		828		757
Storm cost deferrals	1,951		407		1,238		298
Storm cost securitized balance, net	1,023		890		822		682
AROs – nuclear and other	952		1,179		905		1,127
Nuclear asset securitized balance, net	771		830		771		830
Debt fair value adjustment	719		774		—		—
COR regulatory asset	646		371		571		337
Deferred fuel and purchased power	588		2,486		282		1,173
Hedge costs deferrals	352		749		126		323
PISCC and deferred operating expenses	331		357		37		42
Retired generation facilities	281		275		202		220
Customer connect project	257		260		116		125
Grid Deferral	255		210		54		51
Incremental COVID-19 expenses	231		237		89		80
Vacation accrual	228		228		43		43
Deferred asset – Lee and Harris COLA	215		252		10		15
Advanced metering infrastructure (AMI)	204		243		70		92
Demand side management (DSM) / Energy efficiency (EE)	199		201		199		191
CEP deferral	195		193		—		—
NCEMPA deferrals	179		172		179		172
Decoupling	162		115		32		15
Nuclear deferral	134		131		53		42
Deferred pipeline integrity costs	129		133		—		—
COR settlement	110		115		29		30
Coal plant securitization	102		8		39		8
Derivatives – natural gas supply contracts	94		147		—		—
Deferred coal ash handling system costs	77		86		17		21
Qualifying facility contract buyouts	62		68		62		68
Tennessee ARM Deferral	33		20		—		—
Network Integration Transmission Services deferral	31		31		—		—
Transmission expansion obligation	31		30		—		—
East Bend deferrals	24		28		—		—

Propane caverns	24		26		—		—

Other	512		411		156		119
Total regulatory assets	17,010		17,266		8,265		8,091
Less: Current portion	2,756		3,648		1,647		1,661
Total noncurrent regulatory assets	$	14,254	$	13,618	$	6,618	$	6,430
Regulatory Liabilities
COR regulatory liability	$	5,436	$	5,497	$	2,984	$	2,805
Net regulatory liability related to income taxes	5,397		5,901		1,884		2,008
AROs – nuclear and other	2,289		1,673		—		—
Deferred Nuclear PTC	676		—		95		—
Hedge cost deferrals	583		443		281		208
Renewable energy credits	241		237		139		138
Accrued pension and OPEB	232		266		12		—

Deferred fuel and purchased power	223		137		94		14

DSM / EE	58		89		—		—
DOE Settlement	—		32		—		32
Other	984		1,133		291		296
Total regulatory liabilities	16,119		15,408		5,780		5,501
Less: Current portion	1,425		1,369		522		418
Total noncurrent regulatory liabilities	$	14,694	$	14,039	$	5,258	$	5,083

Descriptions of regulatory assets and liabilities summarized in the tables above and below follow. See tables below for recovery and amortization periods at the separate registrants.

AROs – coal ash. Represents deferred depreciation and accretion related to the legal obligation to close ash basins. The costs are deferred until recovery treatment has been determined. See Notes 1 and 10 for additional information.

AROs – nuclear and other. Represents regulatory assets or liabilities, including deferred depreciation and accretion, related to legal obligations associated with the future retirement of property, plant and equipment, excluding amounts related to coal ash. The AROs relate primarily to decommissioning nuclear power facilities. The amounts also include certain deferred gains and losses on NDTF investments. See Notes 1 and 10 for additional information.

Deferred fuel and purchased power. Represents certain energy-related costs that are recoverable or refundable as approved by the applicable regulatory body.

Accrued pension and OPEB. Accrued pension and OPEB represent regulatory assets and liabilities related to each of the Duke Energy Registrants’ respective shares of unrecognized actuarial gains and losses and unrecognized prior service cost and credit attributable to Duke Energy’s pension plans and OPEB plans. The regulatory asset or liability is amortized with the recognition of actuarial gains and losses and prior service cost and credit to net periodic benefit costs for pension and OPEB plans. The accrued pension and OPEB regulatory assets are expected to be recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail.

Storm cost securitized balance, net. Represents the North Carolina portion of storm restoration expenditures related to Hurricane Florence, Hurricane Michael, Hurricane Dorian and Winter Storm Diego (2018 and 2019 events). The South Carolina portion of storm restoration expenditures are related to 2014 Ice Storms Pax and Ulysses, Hurricane Matthew, Hurricane Florence, Hurricane Michael, Hurricane Dorian, and Winter Storms Izzy and Jasper.

Nuclear asset securitized balance, net. Represents the balance associated with Crystal River Unit 3 retirement approved for recovery by the FPSC on September 15, 2015, and the upfront financing costs securitized in 2016 with issuance of the associated bonds. The regulatory asset balance is net of the AFUDC equity portion.

Debt fair value adjustment. Purchase accounting adjustments recorded at the Duke Energy (Parent) level to state the carrying value of debt at fair value in connection with the Duke Energy mergers with Progress Energy in 2012 and Piedmont in 2016. Amount is amortized over the life of the related debt.

Hedge costs deferrals. Amounts relate to realized and unrealized gains and losses on derivatives recorded as a regulatory asset or liability, respectively, until the contracts are settled.

Storm cost deferrals. Represents deferred incremental costs incurred related to major weather-related events.

COR regulatory asset. Represents the excess of spend over funds received from customers to cover the future removal of property, plant and equipment from retired or abandoned sites as property is retired, net of certain deferred gains on NDTF investments.

PISCC and deferred operating expenses. Represents deferred depreciation and operating expenses as well as carrying costs on the portion of capital expenditures placed in service but not yet reflected in retail rates as plant in service.

Retired generation facilities. Represents amounts to be recovered for facilities that have been retired and are probable of recovery.

Deferred asset – Lee and Harris COLA. Represents deferred costs incurred for the canceled Lee and Harris nuclear projects.

Customer connect project. Represents incremental operating expenses and carrying costs on deferred amounts related to the deployment of the new customer information system.

AMI. Represents deferred costs related to the installation of AMI meters and remaining net book value of non-AMI meters to be replaced at Duke Energy Carolinas, net book value of existing meters at Duke Energy Florida, Duke Energy Progress and Duke Energy Ohio and future recovery of net book value of electromechanical meters that have been replaced with AMI meters at Duke Energy Indiana.

Incremental COVID-19 expenses. Represents incremental costs related to ensuring continuity and quality of service in a safe manner during the COVID-19 pandemic.

Vacation accrual. Represents vacation entitlement, which is generally recovered in the following year.

Grid deferral. Represents deferred incremental operation and maintenance expense, depreciation and property taxes associated with grid improvement plans.

DSM/EE. Deferred costs related to various DSM and EE programs recoverable or refundable as approved by the applicable regulatory body.

CEP deferral. Represents deferred depreciation, PISCC and deferred property tax for Duke Energy Ohio Gas capital assets for the CEP.

NCEMPA deferrals. Represents retail allocated cost deferrals and returns associated with the additional ownership interest in assets acquired from NCEMPA in 2015.

Derivatives – natural gas supply contracts. Represents costs for certain long-dated, fixed quantity forward natural gas supply contracts, which are recoverable through PGA clauses.

Deferred pipeline integrity costs. Represents pipeline integrity management costs in compliance with federal regulations.

Nuclear deferral. Includes amounts related to nuclear plant outage and refueling costs, which are deferred and recovered over the nuclear fuel cycle.

COR settlement. Represents approved COR settlements that are being amortized over the average remaining lives, at the time of approval, of the associated assets.

Decoupling. Relates primarily to margin and revenue decoupling.

Deferred coal ash handling system costs. Represents deferred depreciation and returns associated with capital assets related to converting the ash handling system from wet to dry.

Qualifying facility contract buyouts. Represents termination payments for regulatory recovery through the capacity clause.

Network Integration Transmission Services deferral. Represents a deferral of costs and return related transmission costs.

Transmission expansion obligation. Represents transmission expansion obligations related to Duke Energy Ohio's withdrawal from MISO.

East Bend deferrals. Represents amounts to be recovered for deferred costs and depreciation related to the East Bend station.

Propane Caverns. Represents amounts for costs related to propane inventory, the net book value of remaining assets and decommissioning costs at Duke Energy Ohio.

Tennessee ARM Deferral. Represents amounts to be recovered for uncollected revenue for 2022 and deferred depreciation and carrying costs on the portion of capital expenditures placed in service but not yet reflected in rates.

Coal Plant Securitization. Represents the North Carolina portion of incremental depreciation and net book value of certain coal-fired plants to be recovered in a future securitization.

Net regulatory liability related to income taxes. Amounts for all registrants include regulatory liabilities related primarily to impacts from the Tax Act. See Note 24 for additional information. Amounts have no immediate impact on rate base as regulatory assets are offset by deferred tax liabilities.

COR regulatory liability. Represents funds received from customers to cover the future removal of property, plant and equipment from retired or abandoned sites as property is retired. Also includes certain deferred gains on NDTF investments.

DOE Settlement. Represents litigation settlement funds received resulting from the DOE’s failure to accept spent nuclear fuel and other radioactive waste from the Crystal River Unit 3 during 2014-2018 as required under the Nuclear Waste Policy Act.

Deferred Nuclear PTC. Represents the net realizable value of nuclear PTCs that will be passed back to customers over time.

Renewable Energy Credits. Represents certificates for the environmental benefits of renewable energy that will be returned to customers in a future period.

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, 2024.

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, 2024.

Duke Energy Carolinas

Duke Energy Carolinas must limit cumulative distributions subsequent to mergers to (i) the amount of retained earnings on the day prior to the closing of the mergers, plus (ii) any future earnings recorded.

Duke Energy Progress

Duke Energy Progress must limit cumulative distributions subsequent to the mergers between Duke Energy and Progress Energy and Duke Energy and Piedmont to (i) the amount of retained earnings on the day prior to the closing of the respective mergers, plus (ii) any future earnings recorded.

Duke Energy Ohio

Duke Energy Ohio will not declare and pay dividends out of capital or unearned surplus without the prior authorization of the PUCO. Duke Energy Ohio received FERC and PUCO approval to pay dividends from its equity accounts that are reflective of the amount that it would have in its retained earnings account had push-down accounting for the Cinergy merger not been applied to Duke Energy Ohio’s balance sheet. The conditions include a commitment from Duke Energy Ohio that equity, adjusted to remove the impacts of push-down accounting, will not fall below 30% of total capital.

Duke Energy Kentucky is required to pay dividends solely out of retained earnings and to maintain a minimum of 35% equity in its capital structure.

Duke Energy Indiana

Duke Energy Indiana must limit cumulative distributions subsequent to the merger between Duke Energy and Cinergy to (i) the amount of retained earnings on the day prior to the closing of the merger, plus (ii) any future earnings recorded. In addition, Duke Energy Indiana will not declare and pay dividends out of capital or unearned surplus without prior authorization of the IURC.

Piedmont

Piedmont must limit cumulative distributions subsequent to the acquisition of Piedmont by Duke Energy to (i) the amount of retained earnings on the day prior to the closing of the merger, plus (ii) any future earnings recorded.

RATE-RELATED INFORMATION

The NCUC, PSCSC, FPSC, IURC, PUCO, TPUC and KPSC approve rates for retail electric and natural gas services within their states. The FERC approves rates for electric sales to wholesale customers served under cost-based rates (excluding Ohio and Indiana), as well as sales of transmission service. For open regulatory matters, unless otherwise noted, the Subsidiary Registrants and Duke Energy Kentucky cannot predict the outcome or ultimate resolution of their respective matters.

As discussed further below, the Subsidiary Registrants were impacted by significant storms in 2024:

•In August 2024, Hurricane Debby made landfall in Florida as a Category 1 storm, impacting primarily the Duke Energy Florida territory as well as the Duke Energy Carolinas and Duke Energy Progress territories in North Carolina and South Carolina. Approximately 700,000 customers were impacted across Duke Energy's system.

•In September 2024, Hurricane Helene made landfall in Florida as a Category 4 storm and subsequently impacted all of Duke Energy's service territories as the storm moved inland, with the most severe damage occurring in the Duke Energy Florida territory and the Duke Energy Carolinas and Duke Energy Progress territories in North Carolina and South Carolina. Approximately 3.5 million customers were impacted across Duke Energy's system.

•In October 2024, Hurricane Milton made landfall in Florida as a Category 3 storm, impacting more than 1 million customers in the Duke Energy Florida territory.

Each Subsidiary Registrant is responsible for the restoration of service within its respective service territory and the recovery of related storm costs, including financing costs and, as applicable, the replenishment of storm-related reserves. The Subsidiary Registrants are pursuing all available avenues to recover storm-related costs, including insurance recovery and the securitization for certain costs, where applicable. Total estimated costs for storm restoration and rebuilding of infrastructure, including capital expenditures, for hurricanes Debby, Helene and Milton, net of expected insurance recoveries, are estimated to be approximately $2.8 billion, of which approximately $2.6 billion had been incurred as of December 31, 2024, with $0.2 billion estimated to be incurred for rebuilding in 2025. The following shows the total cost estimates for the registrants that were primarily impacted:


(in millions)	Cost Estimate(a)
Duke Energy Carolinas	$	1,150
Duke Energy Progress	450
Duke Energy Florida	1,150

(a) These estimates could change as the rebuilding of infrastructure is finalized. Duke Energy Florida was the only jurisdiction materially impacted by Hurricane Milton.

Duke Energy Carolinas and Duke Energy Progress

Hurricanes Ian, Debby and Helene

In 2022, Hurricane Ian inflicted severe damage to the Duke Energy Carolinas and Duke Energy Progress territories in North Carolina and South Carolina. Total operation and maintenance expenses incurred for restoration efforts were approximately $95 million, with an additional $8 million in capital investments. Approximately $87 million of the operation and maintenance expenses were deferred in Regulatory assets within Other Noncurrent Assets on the Consolidated Balance Sheets as of December 31, 2023 ($32 million and $55 million for Duke Energy Carolinas and Duke Energy Progress, respectively). As of December 31, 2024, $34 million for Duke Energy Carolinas and $47 million for Duke Energy Progress were deferred in Regulatory assets within Other Noncurrent Assets on the Consolidated Balance Sheets.

In 2024, Hurricanes Debby and Helene significantly impacted the Duke Energy Carolinas and Duke Energy Progress territories in North Carolina and South Carolina. As of December 31, 2024, total operation and maintenance expenses incurred for restoration and rebuilding of infrastructure, were approximately $860 million ($612 million and $248 million for Duke Energy Carolinas and Duke Energy Progress, respectively), with an additional $548 million in capital investments ($402 million and $146 million for Duke Energy Carolinas and Duke Energy Progress, respectively). Approximately $802 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, 2024 ($583 million and $219 million for Duke Energy Carolinas and Duke Energy Progress, respectively). These amounts are net of expected insurance recoveries and could change going forward as the rebuilding of infrastructure is finalized.

Duke Energy Carolinas and Duke Energy Progress have regulatory tools to recover storm costs including deferral and securitization. In December 2024, Duke Energy Carolinas and Duke Energy Progress filed their joint petition for review and approval of storm recovery costs (Phase 1) with the NCUC to securitize the North Carolina-retail allocable share of storm costs associated with Hurricanes Helene, Debby and Ian, as well as Hurricane Zeta and Winter Storm Izzy, and the establishment of storm reserves for $200 million at Duke Energy Carolinas and $100 million at Duke Energy Progress. On February 3, 2025, Duke Energy Carolinas and Duke Energy Progress filed their joint petition for financing orders (Phase 2). In February 2025, Duke Energy Carolinas and Duke Energy Progress reached a settlement agreement with the North Carolina Public Staff and other intervening parties that resolves all issues between the parties in the Phase 1 proceeding and removes the establishment of storm reserves from the securitization proceeding. Further, the settlement outlines agreement on certain issues in the Phase 2 proceeding. The evidentiary hearing was held on February 13, 2025. Orders from the NCUC are expected by April 2025 in the Phase 1 proceeding and by June 2025 in the Phase 2 proceeding. Subject to NCUC approvals, Duke Energy Carolinas and Duke Energy Progress expect to securitize the North Carolina-retail allocable share of storm costs by the end of 2025.

On February 17, 2025, Duke Energy Carolinas and Duke Energy Progress filed with the PSCSC notice of intent to file a Joint Petition for Financing Orders no earlier than 30 days from the date of the notice, seeking authority to recover the South Carolina-retail allocable share of storm costs associated with Hurricane Helene through securitization. Such petition is contingent upon the resolution of South Carolina legislative provisions relevant to storm recovery financing.

Nuclear Station Subsequent License Renewal

On June 7, 2021, Duke Energy Carolinas filed a subsequent license renewal (SLR) application for the Oconee Nuclear Station (ONS) with the U.S. Nuclear Regulatory Commission (NRC) to renew ONS’s operating license for an additional 20 years. The SLR would extend operations of the facility from 60 to 80 years. The current licenses for units 1 and 2 expire in 2033 and the license for unit 3 expires in 2034.

In December 2022, the NRC issued the Safety Evaluation Report (SER) for the safety portion of the SLR application. The NRC determined Duke Energy Carolinas met the requirements of the applicable regulations and identified actions that have been taken or will be taken to manage the effects of aging and address time-limited analyses. In February 2023, the Advisory Committee on Reactor Safeguards issued a report to the NRC on the safety aspects of the Oconee SLR application, which concluded that the established programs and commitments made by Duke Energy Carolinas to manage age-related degradation provide confidence that Oconee can be operated in accordance with its current licensing basis for the subsequent period of extended operation without undue risk to the health and safety of the public and the SLR application for Oconee should be approved.

In December 2022, the NRC published a notice in the Federal Register that the NRC would conduct a limited scoping process to gather additional information necessary to prepare an environmental impact statement (EIS) to evaluate the environmental impacts at Oconee during the SLR period. The NRC received comments from the Sierra Club and Beyond Nuclear (Petitioners) and the EPA identifying 18 potential impacts that should be considered by the NRC in the EIS, including climate change and flooding, environmental justice, severe accidents and external events. In February 2024, the NRC issued the Oconee site-specific draft EIS. In April 2024, the Petitioners filed a Hearing Request, which proposed three contentions and in June 2024, the Atomic Safety and Licensing Board (ASLB) convened a pre-hearing conference. On January 17, 2025, the ASLB issued a decision on contention admissibility denying the Petitioners' hearing request. In January 2025, the NRC issued the final EIS and on February 17, 2025, the EPA issued a Notice of Availability for the final EIS. A decision on the SLR for ONS is anticipated from the NRC in the first half of 2025.

Duke Energy Carolinas and Duke Energy Progress intend to seek renewal of operating licenses and 20-year license extensions for all of their nuclear stations.

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)	2024		2023		a Return	Period Ends
Regulatory Assets(a)
AROs – coal ash	$	1,481	$	1,559	(g)	(b)

Storm cost deferrals	691		97		Yes	(b)
Accrued pension and OPEB	668		671			(h)
Deferred fuel and purchased power	298		1,293		(e)	2026
Deferred asset – Lee COLA	205		237			(b)
Hedge costs deferrals	202		405			(b)
Storm cost securitized balance, net	201		208		Yes	2041
Grid Deferral(c)	201		159		Yes	(b)
Incremental COVID-19 expenses	137		152		Yes	(b)
AMI(c)	114		125		Yes	(b)
Vacation accrual	86		87			2025
Nuclear deferral	81		89			2026
COR settlement(c)	81		85		Yes	(b)
Coal plant securitization	63		—		Yes	(b)
Deferred coal ash handling system costs(c)	60		65		Yes	(b)
Customer connect project(c)	54		58		Yes	(b)
Retired generation facilities(c)	54		26		Yes	(b)








PISCC and deferred operating expenses	42		48		Yes	(b)
Decoupling	24		—		Yes	(b)







Other	141		116			(b)
Total regulatory assets	4,884		5,480
Less: Current portion	685		1,564
Total noncurrent regulatory assets	$	4,199	$	3,916
Regulatory Liabilities(a)
AROs – nuclear and other	$	2,289	1,673			(b)
Net regulatory liability related to income taxes(d)	1,951		$	2,200	Yes	(b)
COR regulatory liability(c)	1,479		1,641		Yes	(f)
Deferred Nuclear PTC	581		—		Yes	2030
Hedge cost deferrals	199		158			(b)
Deferred fuel and purchased power	108		85		(e)	2026
Renewable energy credits	102		99		Yes	(b)

DSM / EE(c)	53		87		Yes	(i)
Accrued pension and OPEB	35		106			(h)


Other	413		528			(b)
Total regulatory liabilities	7,210		6,577
Less: Current portion	618		587
Total noncurrent regulatory liabilities	$	6,592	$	5,990

(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.

(d) Includes regulatory liabilities related to the change in the federal tax rate as a result of the Tax Act and the change in the North Carolina tax rate. Portions are included in rate base.

(e) Pays interest on over-recovered costs in North Carolina. Includes certain purchased power costs in North Carolina and South Carolina and costs of distributed energy in South Carolina. The asset balance principally relates to North Carolina costs while the liability balance relates to South Carolina.

(f) Recovered over the life of the associated assets.

(g) Earns a debt and equity return on coal ash expenditures for North Carolina and South Carolina retail customers as permitted by various regulatory orders.

(h) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail.

(i) Includes incentives on DSM/EE investments and is recovered or refunded through an annual rider mechanism.

2023 North Carolina Rate Case

In January 2023, Duke Energy Carolinas filed a PBR application with the NCUC to request an increase in base rate retail revenues. The PBR application included an MYRP to recover projected capital investments during the three-year MYRP period. In addition to the MYRP, the PBR application included an Earnings Sharing Mechanism, Residential Decoupling Mechanism and Performance Incentive Mechanisms (PIMS) as required by HB 951.

In August 2023, Duke Energy Carolinas filed with the NCUC a partial settlement with the Public Staff in connection with its PBR application. The partial settlement included, among other things, agreement on a substantial portion of the North Carolina retail rate base for the historic base case of approximately $19.5 billion and all of the capital projects and related costs to be included in the three-year MYRP, including $4.6 billion (North Carolina retail allocation) projected to go in service over the MYRP period. Additionally, the partial settlement included agreement, with certain adjustments, on depreciation rates, the recovery of grid improvement plan costs and PIMs, Tracking Metrics and the Residential Decoupling Mechanism under the PBR application. On August 28, 2023, Duke Energy Carolinas filed with the NCUC a second partial settlement with the Public Staff resolving additional issues, including the future treatment of nuclear production tax credits related to the IRA, through a stand-alone rider that would provide the benefits to customers. This stand-alone rider was effective in rates beginning January 1, 2025.

On December 15, 2023, the NCUC issued an order approving Duke Energy Carolinas' PBR application, as modified by the partial settlements and the order, including an overall retail revenue increase of $436 million in Year 1, $174 million in Year 2 and $158 million in Year 3, for a combined total of $768 million. The order established an ROE of 10.1% based upon an equity ratio of 53% and approved, with certain adjustments, depreciation rates and the recovery of grid improvement plan costs and certain deferred COVID-related costs. Additionally, the Residential Decoupling Mechanism and PIMs were approved as requested under the PBR application and revised by the partial settlements. As a result of the partial settlements and the order, Duke Energy Carolinas recognized pretax charges of $29 million within Impairment of assets and other charges, and $8 million within Operations, maintenance and other, for the year ended December 31, 2023, on the Consolidated Statements of Operations. Duke Energy Carolinas implemented interim rates on September 1, 2023. New revised Year 1 rates and the residential decoupling were implemented on January 15, 2024.

In February 2024, a number of parties filed Notices of Appeal of the December 15, 2023 NCUC order. Notices of Appeal were filed by the Carolina Industrial Group for Fair Utility Rates (CIGFUR) III, a collection of various electric membership corporations (collectively, the EMCs), and the North Carolina Attorney General’s Office (the AGO). CIGFUR III and the EMCs appealed the interclass subsidy reduction percentage and the Transmission Cost Allocation stipulation. In addition, CIGFUR III appealed the NCUC’s elimination of the equal percentage fuel cost allocation methodology. The AGO appealed several issues including the authorized ROE and certain rate design and accounting matters. On March 1, 2024, Carolina Utility Customers Association, Inc. appealed several issues, including the authorized ROE and certain rate design and accounting matters. In July 2024, the Supreme Court of North Carolina consolidated the appeal with the parallel appeal of the NCUC's order regarding the Duke Energy Progress PBR application. Briefing is complete and oral argument occurred on February 13, 2025. Duke Energy Carolinas anticipates a decision to be issued no later than the fourth quarter of 2025.

2024 South Carolina Rate Case

In January 2024, Duke Energy Carolinas filed a rate case with the PSCSC to request an increase in base rate retail revenues. In May 2024, Duke Energy Carolinas and the Office of Regulatory Staff, as well as other consumer, environmental, and industrial intervening parties, filed an Agreement and Stipulation of Settlement resolving all issues in the base rate proceeding. The major components of the settlement include a $240 million annual customer rate increase, prior to a reduction from the accelerated return to customers of federal unprotected Property, Plant and Equipment related EDIT of $84 million annually over the first two years. The stipulation includes an ROE of 9.94% with an equity ratio of 51.21% and resolves recovery of the Company's continued investments in the grid, its new corporate headquarters and environmental compliance costs. The PSCSC held a hearing in May 2024, to consider evidence supporting the stipulation. On July 3, 2024, the PSCSC issued its final order approving an increase in base rates and approving nearly all components of the Agreement and Stipulation of Settlement. The order revised recovery of certain environmental compliance costs, the only provision of the settlement agreement not fully approved by the PSCSC. As a result, Duke Energy Carolinas recognized pretax charges of $33 million within Impairment of assets and other charges, $2 million within Operations, maintenance and other, partially offset by an $11 million reduction in Interest expense, for the year ended December 31, 2024, on the Consolidated Statements of Operations. Based upon the order, after accelerating the EDIT giveback to customers, the net rate increase is $150 million annually for the first two years. Revised customer rates were effective August 1, 2024, and are based upon a South Carolina retail rate base of $7.4 billion.

Marshall Combustion Turbines CPCN

In March 2024, Duke Energy Carolinas filed with the NCUC an application to construct and operate two hydrogen-capable advanced-class simple-cycle CTs at the site of the existing Marshall Steam Station. The two new CTs – totaling approximately 850 MW – will enable the retirement of Marshall coal units 1 and 2 and provide incremental capacity to support system capacity needs and expanded flexibility to support integration of renewables. Pending regulatory approvals, construction is planned to start in 2026, and the CTs are targeted to be placed into service by the end of 2028. As part of the application, Duke Energy Carolinas noted that Construction Work in Progress for the proposed facility will accrue AFUDC and will not be in rate base, resulting in no impact on Duke Energy Carolinas' North Carolina retail revenue requirement during the construction period. The 2029 North Carolina retail revenue requirement for the proposed facility is estimated to be $104 million, representing an approximate average retail rate increase of 2.2% across all classes. The expert witness hearing concluded in August 2024. On December 2, 2024, the NCUC issued its order granting the CPCN authorizing the construction of the two CTs. Additionally, on December 19, 2024, the NCDEQ issued final air permits for the CTs.

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)	2024		2023		a Return	Period Ends
Regulatory Assets(a)
AROs – coal ash	$	1,322	$	1,218	(g)	(b)
AROs – nuclear and other	900		1,110			(c)
Storm cost securitized balance, net	822		682		Yes	(b)
Accrued pension and OPEB	439		408			(j)
Deferred fuel and purchased power	277		579		(e)	2026
Storm cost deferrals	276		228		Yes	(b)
DSM/EE(d)	188		182		Yes	(h)
NCEMPA deferrals(d)	179		172		(f)	2042
Retired generation facilities(d)	108		126		Yes	(b)
Incremental COVID-19 expenses	89		80			(b)
Hedge costs deferrals	85		260			(b)
AMI(d)	54		68		Yes	(b)
Grid Deferral(d)	54		51		Yes	(b)
Nuclear deferral	53		42			2026
Customer connect project(d)	45		49		Yes	(b)
Vacation accrual	43		43			2025
Coal plant securitization	39		8		Yes	(b)
PISCC and deferred operating expenses	37		42		Yes	2054
Decoupling	32		15		Yes	(b)
COR settlement(d)	29		30		Yes	(b)
Deferred coal ash handling system costs(d)	17		21		Yes	(b)
Deferred asset – Harris COLA	10		15			(b)













Other	83		59			(b)
Total regulatory assets	5,181		5,488
Less: Current portion	626		942
Total noncurrent regulatory assets	$	4,555	$	4,546
Regulatory Liabilities(a)
COR regulatory liability	$	2,984	2,805			(i)
Net regulatory liability related to income taxes(k)	1,320		$	1,420	Yes	(b)
Hedge cost deferrals	151		87			(b)
Renewable energy credits	139		138		Yes	(b)

Deferred Nuclear PTC	95		—		Yes	(b)
Accrued pension and OPEB	12		—			(j)

Deferred fuel and purchased power	10		14		(e)	2026



Other	207		211			(b)
Total regulatory liabilities	4,918		4,675
Less: Current portion	348		300
Total noncurrent regulatory liabilities	$	4,570	$	4,375

(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.

(d) Included in rate base.

(f) South Carolina retail allocated costs are earning a return.

(g) Earns a debt and equity return on coal ash expenditures for North Carolina and South Carolina retail customers as permitted by various regulatory orders.

(h) Includes incentives on DSM/EE investments and is recovered through an annual rider mechanism.

(i) Recovered over the life of the associated assets.

(j) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail.

(k) Includes regulatory liabilities related to the change in the federal tax rate as a result of the Tax Act and the change in the North Carolina tax rate. Portions are included in rate base.

2022 North Carolina Rate Case

In October 2022, Duke Energy Progress filed a PBR application with the NCUC to request an increase in base rate retail revenues. The rate request before the NCUC included an MYRP to recover projected capital investments during the three-year MYRP period. In addition to the MYRP, the PBR Application included an Earnings Sharing Mechanism, Residential Decoupling Mechanism and PIMS as required by HB 951.

In April 2023, Duke Energy Progress filed with the NCUC a partial settlement with Public Staff, which included agreement on many aspects of Duke Energy Progress' three-year MYRP proposal. In May 2023, CIGFUR II joined this partial settlement and Public Staff and CIGFUR II filed a separate settlement reaching agreement on PIMs, Tracking Metrics and the Residential Decoupling Mechanism under the PBR application.

On August 18, 2023, the NCUC issued an order approving Duke Energy Progress' PBR application, as modified by the partial settlements and the order, including an overall retail revenue increase of $233 million in Year 1, $126 million in Year 2 and $135 million in Year 3, for a combined total of $494 million. Key aspects of the order include the approval of North Carolina retail rate base for the historic base case of approximately $12.2 billion and capital projects and related costs to be included in the three-year MYRP, including $3.5 billion (North Carolina retail allocation) projected to go in service over the MYRP period. The order established an ROE of 9.8% based upon an equity ratio of 53% equity and approved, with certain adjustments, depreciation rates and the recovery of grid improvement plan costs and certain deferred COVID-related costs. Additionally, the Residential Decoupling Mechanism and PIMs were approved as requested under the PBR Application and revised by the partial settlements. As a result of the order, Duke Energy Progress recognized pretax charges of $28 million within Impairment of assets and other charges, which primarily related to certain COVID-19 deferred costs, and $8 million within Operations, maintenance and other, for the year ended December 31, 2023, on the Consolidated Statements of Operations. Duke Energy Progress implemented interim rates on June 1, 2023, and implemented revised Year 1 rates and the residential decoupling on October 1, 2023.

In October 2023, CIGFUR II and Haywood Electric Membership Corporation each filed a Notice of Appeal of the August 18, 2023 NCUC order. Both parties were appealing certain matters that do not impact the overall revenue requirement in the rate case. Specifically, they appealed the interclass subsidy reduction percentage, and CIGFUR II also appealed the Customer Assistance Program and the equal percentage fuel cost allocation methodology. On November 6, 2023, the AGO filed a Notice of Cross Appeal of the NCUC’s determination regarding the exclusion of electric vehicle revenue from the residential decoupling mechanism. On November 9, 2023, Duke Energy Progress, the Public Staff, CIGFUR II, and a number of other parties reached a settlement pursuant to which CIGFUR II agreed not to pursue its appeal of the Customer Assistance Program. In July 2024, the Supreme Court of North Carolina consolidated the appeal with the parallel appeal of the NCUC's order regarding the Duke Energy Carolinas PBR application. Briefing is complete and oral arguments occurred on February 13, 2025. Duke Energy Progress anticipates a decision to be issued no later than the fourth quarter of 2025.

2023 South Carolina Storm Securitization

On May 31, 2023, Duke Energy Progress filed a petition with the PSCSC requesting authorization for the financing of Duke Energy Progress' storm recovery costs through securitization due to storm recovery activities required as a result of the following storms: Pax, Ulysses, Matthew, Florence, Michael, Dorian, Izzy and Jasper. On September 8, 2023, Duke Energy Progress filed a comprehensive settlement agreement with all parties on all cost recovery issues raised in the storm securitization proceeding.

The evidentiary hearing occurred in September 2023. On September 20, 2023, the PSCSC approved the comprehensive settlement agreement and on October 13, 2023, the PSCSC issued its financing order. The storm recovery bonds of $177 million were issued by Duke Energy Progress in April 2024 and storm recovery charges were effective May 1, 2024. See Notes 7 and 18 for more information.

2022 South Carolina Rate Case

On September 1, 2022, Duke Energy Progress filed an application with the PSCSC to request an increase in base rate retail revenues. On January 12, 2023, Duke Energy Progress and the ORS, as well as other consumer, environmental, and industrial intervening parties, filed a comprehensive Agreement and Stipulation of Settlement resolving all issues in the base rate proceeding. The major components of the stipulation include an ROE of 9.6% based upon an equity ratio of 52.43% along with the establishment of a storm reserve to help offset the costs of major storms. The stipulation provided for a $52 million annual customer rate increase prior to the reduction from the accelerated return to customers of federal unprotected Property, Plant and Equipment related EDIT; after extending the remaining EDIT giveback to customers to 33 months, the net annual retail rate increase is approximately $36 million. It also allowed continuation of deferral treatment of coal ash basin closure costs and supports an amortization period for remaining coal ash closure costs in this rate case of seven years. Duke Energy Progress agreed not to seek recovery of approximately $50 million of deferred coal ash expenditures related to retired sites in this rate case (South Carolina retail allocation). The 2021 Depreciation Study was accepted as proposed in this case, as adjusted for certain recommendations from ORS and includes accelerated retirement dates for certain coal units as originally proposed. The PSCSC held a hearing in January 2023 and a final written order was issued on March 8, 2023. New rates went into effect April 1, 2023.

Person County Combined Cycle CPCNs

In March 2024, Duke Energy Progress filed with the NCUC its application to construct and operate a 1,360-MW hydrogen-capable, advanced-class CC generating facility in Person County at the site of the existing Roxboro Plant. Subject to negotiation of final contractual terms, the new Roxboro CC will be co-owned with the North Carolina Electric Membership Corporation (NCEMC), with Duke Energy Progress owning approximately 1,135 MW and NCEMC owning the remaining 225 MW. Pending regulatory approvals, construction is planned to start in 2026, with the CC targeted to be placed in service by the end of 2028. The CC will allow for the retirement of Roxboro’s coal-fired units 1 and 4. As part of the application, Duke Energy Progress noted that the recovery of Construction Work in Progress during the construction period for the proposed facility may be pursued in a future rate case. The 2029 North Carolina retail revenue requirement for the proposed facility is estimated to be $98 million, representing an approximate average retail rate increase of 2.6% across all classes. The expert witness hearing concluded in August 2024. On December 6, 2024, the NCUC issued its order granting the CPCN authorizing the construction of the CC. Additionally, on December 19, 2024, the NCDEQ issued a final air permit for the CC.

On February 7, 2025, Duke Energy Progress filed with the NCUC its application to construct and operate a second 1,360-MW hydrogen-capable, advanced-class CC unit in Person County at the Roxboro Plant. NCEMC has also notified Duke Energy Progress of NCEMC's intent to co-own approximately 225 MW of the second CC and Duke Energy Progress and NCEMC plan to begin negotiations on the contractual arrangement in the second quarter of 2025. Pending regulatory approvals, construction of the second CC is planned to start in 2026 with the unit targeted to be placed in service by the end of 2029. As part of the application, Duke Energy Progress noted that the recovery of Construction Work in Progress during the construction period for the proposed facility may be pursued in a future rate case. The 2030 North Carolina retail revenue requirement for the proposed facility is estimated to be $113 million, representing an approximate average retail rate increase of 2.6% across all classes. The air permit issued by the NCDEQ on December 19, 2024, also pertains to the second CC.

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)	2024		2023		a Return	Period Ends
Regulatory Assets(a)
Storm cost deferrals(c)	$	962	70		(e)	(b)
Nuclear asset securitized balance, net	771		830			2036
COR regulatory asset	571		337		(d)	(b)
Accrued pension and OPEB(c)	389		349		Yes	(f)
Retired generation facilities(c)	94		94		Yes	2044
Customer connect project(c)	71		76		Yes	2037
Qualifying facility contract buyouts(c)	62		68		Yes	2034
Hedge costs deferrals(c)	41		63		Yes	2038
AMI(c)	16		24		Yes	2032
AROs – coal ash	13		$	12		(b)
AROs – nuclear and other	5		17			(b)
Deferred fuel and purchased power	5		594		(e)	2025






















Other	86		69		(d)	(b)
Total regulatory assets	3,086		2,603
Less: Current portion	1,022		720
Total noncurrent regulatory assets	$	2,064	$	1,883
Regulatory Liabilities(a)
Net regulatory liability related to income taxes(c)	$	564	$	588		(b)
Hedge cost deferrals(c)	130		121		Yes	(b)
DOE Settlement	—		32



Deferred fuel and purchased power(c)	84		—		(e)	2025




Other	84		85		(d)	(b)
Total regulatory liabilities	862		826
Less: Current portion	174		118
Total noncurrent regulatory liabilities	$	688	$	708

(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.

(d) Certain costs earn/pay a return.

(e) Earns commercial paper rate.

(f) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail.

2021 Settlement Agreement

In January 2021, Duke Energy Florida filed the 2021 Settlement with the FPSC. The parties to the 2021 Settlement include Duke Energy Florida, the Office of Public Counsel (OPC), the Florida Industrial Power Users Group, White Springs Agricultural Chemicals, Inc. d/b/a PCS Phosphate and NUCOR Steel Florida, Inc. (collectively, the "Parties").

Pursuant to the 2021 Settlement, the Parties agreed to a base rate stay-out provision that expires year-end 2024; however, Duke Energy Florida is allowed an increase to its base rates of an incremental $67 million in 2022, $49 million in 2023 and $79 million in 2024, subject to adjustment in the event of tax reform during the years 2021, 2022 and 2023. The Parties also agreed to an ROE band of 8.85% to 10.85% with a midpoint of 9.85% based upon an equity ratio of 53%. The ROE band can be increased by 25 basis points if the average 30-year U.S. Treasury rate increases 50 basis points or more over a six-month period in which case the midpoint ROE would rise from 9.85% to 10.10%. On July 25, 2022, this provision was triggered. Duke Energy Florida filed a petition with the FPSC in August 2022, to increase the ROE effective August 2022 with a base rate increase effective January 1, 2023. The FPSC approved this request on October 4, 2022. The 2021 Settlement Agreement also provided that Duke Energy Florida would be able to retain $173 million of the expected DOE award from its lawsuit to recover spent nuclear fuel to mitigate customer rates over the term of the 2021 Settlement. In return, Duke Energy Florida was permitted to recognize the $173 million into earnings through the approved settlement period. Duke Energy Florida settled the DOE lawsuit and received payment of approximately $180 million on June 15, 2022, of which the retail portion was approximately $154 million. The 2021 Settlement authorized Duke Energy Florida to collect the difference between $173 million and the $154 million retail portion of the amount received through the capacity cost recovery clause. As of December 31, 2024, Duke Energy Florida has recognized $173 million (pretax) into earnings, including $32 million and $141 million recognized during the year ended December 31, 2024, and 2023, respectively.

The 2021 Settlement also contained a provision to recover or flow back the effects of tax law changes. As a result of the IRA enacted in August 2022, Duke Energy Florida is eligible for PTCs associated with solar facilities placed in service beginning in January 2022. Duke Energy Florida filed a petition with the FPSC in October 2022, to reduce base rates effective January 1, 2023, by $56 million to flow back the expected 2023 PTCs and to flow back the expected 2022 PTCs via an adjustment to the capacity cost recovery clause. On December 14, 2022, the FPSC issued an order approving Duke Energy Florida’s petition. See Note 24 for additional information on the IRA.

In addition to these terms, the 2021 Settlement contained provisions related to the accelerated depreciation of Crystal River Units 4-5, the approval of approximately $1 billion in future investments in new cost-effective solar power, the implementation of a new Electric Vehicle Charging Station Program and the deferral and recovery of costs in connection with the implementation of Duke Energy Florida’s Vision Florida program, which explores various emerging non-carbon emitting generation technology, distributed technologies and resiliency projects, among other things. The 2021 Settlement also resolved remaining unrecovered storm costs for Hurricane Michael and Hurricane Dorian.

The FPSC approved the 2021 Settlement on May 4, 2021, issuing an order on June 4, 2021. Revised customer rates became effective January 1, 2022, with subsequent base rate increases effective January 1, 2023, and January 1, 2024.

Clean Energy Connection

In July 2020, Duke Energy Florida petitioned the FPSC for approval of a voluntary solar program consisting of 10 new solar generating facilities with combined capacity of 749 MW. The FPSC approved the program in January 2021, allowing participants to support cost-effective solar development in Florida by paying a subscription fee based on per kilowatt subscriptions and receiving a credit on their bill based on the actual generation associated with their portion of the solar portfolio. The 10 new solar generation facilities were completed and all of the remaining sites were in-service by the end of 2024 at a cost of approximately $1.1 billion. These investments are included in base rates, offset by the revenue from the subscription fees, with credits included in the fuel cost recovery clause.

In February 2021, the League of United Latin American Citizens (LULAC) filed a notice of appeal of the FPSC’s order approving the Clean Energy Connection to the Supreme Court of Florida. The Supreme Court of Florida heard oral arguments in the appeal in February 2022. On May 27, 2022, the Supreme Court of Florida issued an order remanding the case back to the FPSC so that the FPSC can amend its order to better address some of the arguments raised by LULAC. In September 2022, the FPSC issued a revised order and submitted it to the Supreme Court of Florida. The Supreme Court of Florida requested that the parties file supplemental briefs regarding the revised order, which were filed in February 2023. LULAC has filed a request for Oral Argument on the issues discussed in the supplemental briefs, but the court has yet to rule on that request. The FPSC approval order remains in effect pending the outcome of the appeal.

Storm Protection Plan

At least every three years, Duke Energy Florida must file a Storm Protection Plan (SPP) with the FPSC. Each plan covers a 10-year period and includes investments in transmission and distribution meant to strengthen infrastructure, reduce outage times associated with extreme weather events, reduce restoration costs and improve overall service reliability. In April 2022, Duke Energy Florida filed an SPP for approval with the FPSC for the 2023-2032 time frame. The plan reflected approximately $7 billion of capital investment in transmission and distribution. The evidentiary hearing began in August 2022. In October 2022, the FPSC approved Duke Energy Florida's plan with one modification to remove the transmission loop radially fed program, representing a reduction of approximately $80 million over the 10-year period starting in 2025. In December 2022, the OPC filed a notice of appeal of this order to the Florida Supreme Court and briefs were filed by the OPC and Duke Energy Florida during 2023. On November 14, 2024, the Florida Supreme Court issued an order upholding the FPSC's approval of Duke Energy Florida's plan.

On January 15, 2025, Duke Energy Florida filed an SPP for approval with the FPSC for the 2026-2035 time frame reflecting approximately $7 billion of capital investment in transmission and distribution. The FPSC must approve, with modification, or deny the plan no later than 180 days after filing. A hearing has been scheduled to begin May 20, 2025.

Hurricanes Ian and Idalia

In September 2022, much of Duke Energy Florida’s service territory was impacted by Hurricane Ian, which caused significant damage resulting in more than 1.1 million outages. After depleting any existing storm reserves, which were approximately $107 million before Hurricane Ian, Duke Energy Florida is permitted to petition the FPSC for recovery of additional incremental operation and maintenance costs resulting from the storm and to replenish the retail customer storm reserve to approximately $132 million. Duke Energy Florida filed its petition for cost recovery of various storms, including Hurricane Ian, and replenishment of the storm reserve in January 2023, seeking recovery of $442 million, for recovery over 12 months beginning with the first billing cycle in April 2023. In March 2023, the FPSC approved this request for interim recovery, subject to refund, and ordered Duke Energy Florida to file documentation of the total actual storm costs, once known. Duke Energy Florida filed documentation evidencing its total actual storm costs of $431 million in September 2023. The FPSC approved the prudence of these costs in May 2024.

In August 2023, Hurricane Idalia made landfall on Florida’s gulf coast, causing damage and impacting more than 200,000 customers across Duke Energy Florida's service territory. In October 2023, Duke Energy Florida requested to combine the $92 million retail portion of the deferred estimated Hurricane Idalia costs with $74 million of costs projected to be collected after December 31, 2023, under the existing approved storm cost recovery and storm surcharge. This $74 million of costs relates primarily to the approved ongoing replenishment of the storm reserves. In December 2023, the FPSC approved recovery of the total $166 million over 12 months beginning with its first billing cycle in January 2024, replacing the previously approved storm cost recovery and storm surcharge, and ordered Duke Energy Florida to file documentation of the total actual Idalia related storm costs, once known. Revised rates were effective January 1, 2024. Duke Energy Florida filed documentation evidencing its total Idalia actual storm costs of $98 million in September 2024.

2024 Florida Rate Case

In April 2024, Duke Energy Florida filed a formal request for new base rates with the FPSC. Duke Energy Florida proposed a three-year rate plan that would begin in January 2025, once its current base rate settlement agreement concludes at the end of 2024. Duke Energy Florida proposed multiyear rate increases that use the projected 12-month periods ending December 31, 2025, 2026, and 2027 as the test years, with adjusted rates to be effective with the first billing period of January 2025, 2026, and 2027, respectively.

In July 2024, Duke Energy Florida filed a settlement agreement with the FPSC. The parties to the settlement include Duke Energy Florida, the Office of Public Counsel and other intervening parties. Pursuant to the settlement, the parties agreed to a base rate stay-out provision that expires year-end 2027; however, Duke Energy Florida is allowed an increase to its base rates in 2025 and 2026, as well as utilization of certain tax benefits in lieu of a revenue increase in 2027. Additionally, revenue increases related to solar investments will be recovered via the Solar Base Rate Adjustment mechanism. The parties also agreed to an ROE band of 9.3% to 11.3% with a midpoint of 10.3% and an equity ratio of 53%. The agreement provides for $203 million and $59 million in base rate increases in 2025 and 2026, respectively, as well as increases associated with investments in 12 new solar facilities as they come on line. In August 2024, the FPSC approved the settlement agreement without modification and a final order was issued on November 12, 2024. New rates were effective January 1, 2025.

Hurricanes Debby, Helene and Milton

In August 2024, Hurricane Debby made landfall in Florida as a Category 1 storm, and in September 2024, Hurricane Helene made landfall in Florida as a Category 4 storm, which caused significant damage. In October 2024, Hurricane Milton made landfall in Florida as a Category 3 storm, impacting roughly half of the customers Duke Energy Florida serves in the state. Duke Energy Florida has certain existing storm reserve regulatory liability amounts, which will be applied to recovery of the 2024 storm costs. After depleting any existing storm reserves, which were approximately $63 million as of July 31, 2024, before hurricanes Debby, Helene and Milton, Duke Energy Florida is permitted to petition the FPSC for recovery of additional incremental operation and maintenance costs resulting from the storm and to replenish the retail customer storm reserve to approximately $132 million. Duke Energy Florida filed its petition for cost recovery for all three storms, including replenishment of the storm reserve, on December 27, 2024, seeking recovery of approximately $1.1 billion, for recovery over 12 months beginning with the first billing cycle in March 2025. Approximately $936 million of the operation and maintenance expenses are deferred in Regulatory assets within Current assets as of December 31, 2024. Approximately $69 million of capital related to these storms will be sought for recovery in future base rate case filings. On February 4, 2025, the FPSC voted to approve Duke Energy Florida's request for recovery of these storm costs as filed.

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)	2024		2023		a Return	Period Ends
Regulatory Assets(a)
CEP deferral	$	195	193		Yes	(b)

Accrued pension and OPEB	131		123			(d)
COR regulatory asset	75		34			(b)
Customer connect project	44		49			(b)
Network Integration Transmission Services deferral	31		31		Yes	(b)
Transmission expansion obligation	31		30			(b)
Decoupling	29		25			(b)
Deferred pipeline integrity costs	28		30		Yes	(b)
East Bend deferrals(c)	24		28		Yes	(b)
Propane caverns	24		26			(b)
PISCC and deferred operating expenses(c)	15		15		Yes	2083
AROs – coal ash	14		$	17	Yes	(b)
Deferred fuel and purchased gas costs	8		20			2025
AMI	8		13			(b)
Storm cost deferrals	5		12			2025


















Other	131		103			(b)
Total regulatory assets	793		749
Less: Current portion	88		73
Total noncurrent regulatory assets	$	705	$	676
Regulatory Liabilities(a)
Net regulatory liability related to income taxes	$	432	$	466		(b)
Accrued pension and OPEB	14		17			(d)
Deferred fuel and purchased gas costs	—		15			2025








Other	53		55			(b)
Total regulatory liabilities	499		553
Less: Current portion	34		56
Total noncurrent regulatory liabilities	$	465	$	497

(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.

(d) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail.

Duke Energy Ohio Electric Base Rate Case

In October 2021, Duke Energy Ohio filed an electric distribution base rate case application with the PUCO. In September 2022, Duke Energy Ohio filed a Stipulation and Recommendation with the PUCO, which included an increase in overall electric distribution base rates of approximately $23 million with an equity ratio of 50.5% and an ROE of 9.5%. The stipulation was among all but one party to the proceeding. The PUCO issued an order on December 14, 2022, approving the Stipulation without material modification and new rates went into effect on January 3, 2023. The Ohio Consumers' Counsel (OCC) filed an application for rehearing in January 2023, arguing the Stipulation was unreasonable, discriminatory and denied OCC due process. In March 2024, the PUCO denied OCC's rehearing application. The deadline for OCC to seek an appeal has expired and the matter is now closed.

Energy Efficiency Cost Recovery

In response to changes in Ohio law that eliminated Ohio's energy efficiency mandates, the PUCO issued an order on February 26, 2020, directing utilities to wind down their demand-side management programs by September 30, 2020, and to terminate the programs by December 31, 2020. In March 2020, Duke Energy Ohio filed an application for rehearing seeking clarification on the final true up and reconciliation process after 2020. Effective January 1, 2021, Duke Energy Ohio suspended its energy efficiency programs. In August 2023, the PUCO issued its decision approving the Company’s request for recovery and final true up of energy efficiency program costs, lost distribution revenues and performance incentives from calendar years 2018 through 2020, resulting in $14 million of Regulated electric revenue on the Consolidated Statements of Operations for the year ended December 31, 2023, and resolving all outstanding issues in these proceedings. Revised rates were effective September 1, 2023.

Duke Energy Ohio Natural Gas Base Rate Case

In June 2022, Duke Energy Ohio filed a natural gas base rate case application with the PUCO. The drivers for this case are capital invested since Duke Energy Ohio's last natural gas base rate case in 2012. Duke Energy Ohio also sought to adjust the caps on its CEP Rider. In April 2023, Duke Energy Ohio filed a stipulation with all parties to the case except the OCC. In the stipulation, the parties agreed to approximately $32 million in revenue increases with an equity ratio of 52.32% and an ROE of 9.6%, and adjustments to the CEP Rider caps. The stipulation was opposed by the OCC at an evidentiary hearing that concluded in May 2023. On November 1, 2023, PUCO issued an order approving the stipulation as filed and new rates went into effect November 1, 2023. In December 2023, the OCC filed an application for rehearing and the PUCO granted OCC's application for rehearing for further consideration of issues raised. As a result of a Supreme Court of Ohio decision regarding procedural issues related to applications for rehearing, PUCO denied OCC’s rehearing request. In October 2024, the OCC filed its Notice of Appeal with the Ohio Supreme Court. OCC's initial brief was filed January 27, 2025.

Duke Energy Ohio Electric Security Plan

In April 2024, Duke Energy Ohio filed with the PUCO a request for an Electric Security Plan (ESP). The ESP application proposes a three-year term from June 1, 2025, through May 31, 2028, and includes continuation of market-based customer rates through competitive procurement processes for generation and continuation and expansion of existing rider mechanisms. Duke Energy Ohio is proposing a new rider mechanism relating to electric distribution infrastructure modernization programs, which may be enabled by and partially funded through federal or state funding opportunities, future battery storage projects, and two proposed electric vehicle programs. Additional proposed new rider mechanisms are related to solar for all investments for low-income and disadvantaged communities, low-income senior citizen bill assistance, and energy efficiency and demand-side management programs.

In November 2024, Duke Energy Ohio filed a stipulation with majority of the intervenors signed as either signatory or non-opposing parties. The stipulation includes the continuation of market-based customer rates through competitive procurement auctions and the continuation of all existing riders. It further establishes new caps for certain riders. Duke Energy Ohio has also agreed to withdraw its proposals for an infrastructure modernization rider, battery storage projects and electric vehicle programs. The stipulation includes a residential EE program with provisions for low-income customers. The evidentiary hearing concluded January 23, 2025. A briefing schedule has been ordered with final reply briefs due March 14, 2025.

MGP Cost Recovery

In an order issued in 2013, the PUCO approved Duke Energy Ohio's deferral and recovery of costs related to environmental remediation at two sites (East End and West End) that housed former MGP operations. Duke Energy Ohio made annual applications with the PUCO to recover its incremental remediation costs consistent with the PUCO’s directive in Duke Energy Ohio’s 2012 natural gas base rate case.

A Stipulation and Recommendation was filed jointly by Duke Energy Ohio, the Staff, the Office of the Ohio Consumers' Counsel and the Ohio Energy Group in August 2021, which was approved without modification by the PUCO in April 2022. The Stipulation and Recommendation resolved all open issues regarding MGP remediation costs incurred between 2013 and 2019, Duke Energy Ohio’s request for additional deferral authority beyond 2019 and the pending issues related to the Tax Act described below as it related to Duke Energy Ohio’s natural gas operations. As a result of the approval of the Stipulation and Recommendation, Duke Energy Ohio recognized pretax charges of approximately $15 million to Operating revenues, regulated natural gas and $58 million to Operation, maintenance and other and a tax benefit of $72 million to Income Tax (Benefit) Expense in the Consolidated Statements of Operations for the year ended December 31, 2022. The Stipulation and Recommendation further acknowledged Duke Energy Ohio’s ability to file a request for additional deferral authority in the future related to environmental remediation of any MGP impacts in the Ohio River, if necessary, subject to specific conditions. In June 2022, the PUCO granted rehearing requests for further consideration of Interstate Gas Supply, Inc. (IGS) and The Retail Energy Supply Association (RESA). As a result of a Supreme Court of Ohio decision regarding procedural issues related to applications for rehearing, PUCO denied these rehearing requests. On October 28, 2024, RESA and IGS filed an appeal with the Supreme Court of Ohio. On January 10, 2025, RESA and IGS withdrew their appeal and the Supreme Court of Ohio dismissed the appeal on January 14, 2025. This matter is now resolved.

Tax Act – Ohio

In December 2018, Duke Energy Ohio filed an application to change its base rate tariffs and establish a rider to implement the benefits of the Tax Act for natural gas customers. The rider would flow through to customers the benefit of the reduction in the statutory federal tax rate from 35% to 21% since January 1, 2018, all future benefits of the lower tax rates and a full refund of deferred income taxes collected at the higher tax rates in prior years. Deferred income taxes subject to normalization rules would be refunded consistent with federal law and deferred income taxes not subject to normalization rules would be refunded over a 10-year period. An evidentiary hearing occurred in August 2019. The Stipulation and Recommendation filed in August 2021, and approved on April 20, 2022, disclosed in the MGP Cost Recovery matter above, resolved the outstanding issues in this proceeding by providing customers a one-time bill credit for the reduction in the statutory federal tax rate from 35% to 21% since January 1, 2018, through June 1, 2022, and reducing base rates going forward. Deferred income taxes not subject to normalization rules were written off. Deferred income taxes subject to normalization rules are refunded consistent with federal law through a rider. The commission granted the rehearing requests of IGS and RESA for further consideration. As a result of a Supreme Court of Ohio decision regarding procedural issues related to applications for rehearing, PUCO denied these rehearing requests. On October 28, 2024, RESA and IGS filed an appeal with the Supreme Court of Ohio. On January 10, 2025, RESA and IGS withdrew their appeal and the Supreme Court of Ohio dismissed the appeal on January 14, 2025. This matter is now resolved.

Duke Energy Kentucky 2022 Electric Base Rate Case

In December 2022, Duke Energy Kentucky filed a base rate case with the KPSC driven by capital investments to strengthen the electricity generation and delivery systems along with adjusted depreciation rates for the East Bend and Woodsdale CT generation stations. Duke Energy Kentucky also requested approval for new programs and tariff updates, including a voluntary community-based renewable subscription program and two electric vehicle charging programs. The KPSC issued an order on October 12, 2023, including a $48 million increase in base revenues, an ROE of 9.75% for electric base rates and 9.65% for electric riders and an equity ratio of 52.145%. New rates went into effect October 13, 2023. The Company's request to align the depreciation rates of East Bend with a 2035 retirement date was denied and the KPSC ordered depreciation rates with a 2041 retirement date for the unit. The KPSC did approve the request to align the depreciation rates of Woodsdale CT with a 2040 retirement date and denied the voluntary community-based renewable subscription program and the two electric vehicle charging programs.

In November 2023, Duke Energy Kentucky filed for rehearing requesting certain matters be reconsidered by the KPSC and the KPSC granted in part and denied in part the Company's request for rehearing. On July 1, 2024, the KPSC issued its final order on rehearing, ruling in Duke Energy Kentucky's favor on nearly all issues. However, the KPSC ordered Duke Energy Kentucky to refund alleged over collections since the KPSC's October 12, 2023, order. On July 10, 2024, the KPSC issued an order correcting the base fuel rate used to calculate new base rates in its July 1, 2024, order and its calculation of Duke Energy Kentucky's Street Lighting Rate. New rates were implemented in August 2024.

On December 14, 2023, Duke Energy Kentucky filed an appeal with the Franklin County Circuit Court on certain matters for which the KPSC denied rehearing, specifically as it relates to including decommissioning costs in depreciation rates for East Bend and Woodsdale. Duke Energy Kentucky and Appellee briefs were filed in 2024.

Duke Energy Kentucky 2024 Electric Base Rate Case

On December 2, 2024, Duke Energy Kentucky filed a base rate case with the KPSC requesting an annualized increase in electric base rates of approximately $70 million and an ROE of 10.85% with an equity ratio of 52.728%. This is an overall increase of approximately 14.7%. The request for the rate increase is driven by capital investments to strengthen the electricity generation and delivery systems. New rates are anticipated to go into effect around July 2, 2025. An evidentiary hearing is scheduled to begin on May 21, 2025.

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)	2024		2023		a Return	Period Ends
Regulatory Assets(a)
AROs – coal ash	$	554	$	408	Yes	(b)

PISCC and deferred operating expenses(c)	237		241		Yes	(b)
Accrued pension and OPEB	212		208			(e)
Retired generation facilities(c)	25		29		Yes	2030
Hedge costs deferrals	23		19			(b)
Customer connect project	19		19			(b)


Storm cost deferrals	17		11			(b)


AMI	12		13			2031





















Other	54		48			(b)
Total regulatory assets	1,153		996
Less: Current portion	113		102
Total noncurrent regulatory assets	$	1,040	$	894
Regulatory Liabilities(a)
Net regulatory liability related to income taxes	$	725	$	794		(b)
COR regulatory liability	434		496			(d)
Accrued pension and OPEB	139		109			(e)
Hedge cost deferrals	103		77			(b)
Deferred fuel and purchased power	21		23			2025






Other	165		169			(b)
Total regulatory liabilities	1,587		1,668
Less: Current portion	183		209
Total noncurrent regulatory liabilities	$	1,404	$	1,459

(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.

(d) Refunded over the life of the associated assets.

(e) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail.

2019 Indiana Rate Case

In July 2019, Duke Energy Indiana filed a general rate case with the IURC for a rate increase for retail customers. On June 29, 2020, the IURC issued an order in the rate case approving a revenue increase of $146 million before certain adjustments and ratemaking refinements. The order approved Duke Energy Indiana's requested forecasted rate base of $10.2 billion as of December 31, 2020, including the Edwardsport Integrated Gasification Combined Cycle (IGCC) Plant. The IURC reduced Duke Energy Indiana's request by slightly more than $200 million, when accounting for the utility receipts tax and other adjustments. Step one rates were estimated to be approximately 75% of the total rate increase and became effective on July 30, 2020. Step two rates estimated to be the remaining 25% of the total rate increase were approved on July 28, 2021, and implemented in August 2021.

Several groups appealed the IURC order to the Indiana Court of Appeals. The Indiana Court of Appeals affirmed the IURC decision on May 13, 2021. However, upon appeal by the Indiana Office of Utility Consumer Counselor (OUCC) and the Duke Industrial Group in March 2022, the Indiana Supreme Court found that the IURC erred in allowing Duke Energy Indiana to recover coal ash costs incurred before the IURC’s rate case order in June 2020. The Indiana Supreme Court found that allowing Duke Energy Indiana to recover coal ash costs incurred between rate cases that exceeded the amount built into base rates violated the prohibition against retroactive ratemaking. The IURC’s order was remanded to the IURC for additional proceedings consistent with the Indiana Supreme Court’s opinion. As a result of the court's opinion, Duke Energy Indiana recognized pretax charges of approximately $211 million to Impairment of assets and other charges and $46 million to Operating revenues in the Consolidated Statements of Operations for the year ended December 31, 2022. Duke Energy Indiana filed a request for rehearing with the Supreme Court in April 2022, which the court denied. In February 2023, Duke Energy Indiana filed a settlement agreement reached with the OUCC and Duke Industrial Group, which includes an agreed amount of approximately $70 million of refunds to be paid to customers. The IURC approved this settlement agreement in its entirety on April 12, 2023. In June 2023, Duke Energy Indiana commenced refunding the approximate $70 million to customers in accordance with the settlement agreement, which was completed in May 2024.

Indiana Coal Ash Recovery

In Duke Energy Indiana’s 2019 rate case, the IURC also opened a subdocket for post-2018 coal ash related expenditures. Duke Energy Indiana filed testimony in April 2020, in the coal ash subdocket requesting recovery for the post-2018 coal ash basin closure costs for plans that have been approved by the Indiana Department of Environmental Management (IDEM) as well as continuing deferral, with carrying costs, on the balance. On November 3, 2021, the IURC issued an order allowing recovery for post-2018 coal ash basin closure costs for the plans that have been approved by IDEM, as well as continuing deferral, with carrying costs, on the balance. The OUCC and the Duke Industrial Group appealed. The Indiana Court of Appeals issued its opinion on February 21, 2023, reversing the IURC's order to the extent that it allowed Duke Energy Indiana to recover federally mandated costs incurred prior to the IURC's November 3, 2021, order. In addition, the court found that any costs incurred pre-petition to determine federally mandated compliance options were not specifically authorized by the statute and should also be disallowed. As a result of the Indiana Court of Appeals' opinion, Duke Energy Indiana recognized a pretax charge of approximately $175 million to Impairment of assets and other charges for the year ended December 31, 2022.

In the second quarter of 2023, Duke Energy Indiana filed its proposal to remove from rates certain costs incurred prior to the IURC's November 3, 2021, order date. On September 20, 2023, the commission approved the Company's proposal to remove the costs from its rates and assessed simple interest of the refunds of 4.71%, beginning from when the costs were initially recovered from customers. Duke Energy Indiana included a request to recover the pre-order costs denied by the Indiana Court of Appeals and certain future coal ash closure costs as part of depreciation costs in the 2024 Indiana Rate Case.

On August 30, 2023, Duke Energy Indiana filed a new petition under the amended version of the federal mandate statute for additional post-2018 coal ash closure costs for the remaining basins not included in the Indiana coal ash recovery case from 2020. An evidentiary hearing was held in January 2024. On May 8, 2024, the IURC issued a CPCN and approved these coal ash related compliance projects as federally mandated compliance projects. In June 2024, the Citizens Action Coalition of Indiana (CAC) filed a motion to appeal the IURC order granting the coal ash CPCN proceeding and approving the coal ash related compliance projects. Briefing was completed January 24, 2025.

TDSIC 2.0

In November 2021, Duke Energy Indiana filed for approval of the Transmission, Distribution, Storage Improvement Charge 2.0 investment plan for 2023-2028 (TDSIC 2.0). On June 15, 2022, the IURC approved, without modification, TDSIC 2.0, which includes approximately $2 billion in transmission and distribution investments selected to improve customer reliability, harden and improve resiliency of the grid, enable expansion of renewable and distributed energy projects and encourage economic development. In July 2022, the OUCC filed a notice of appeal to the Indiana Court of Appeals in Duke Energy Indiana’s TDSIC 2.0 proceeding. The Indiana Court of Appeals issued its opinion on March 9, 2023, affirming the IURC’s order in its entirety. The Duke Industrial Group filed a petition to transfer to the Indiana Supreme Court. On December 19, 2024, the Indiana Supreme Court affirmed the Indiana Court of Appeals decision, concluding there was substantial evidence that the IURC's conclusion was reasonable and the TDSIC 2.0 plan met the statutory requirements. On January 21, 2025, the Duke Industrial Group filed a motion for rehearing.

2024 Indiana Rate Case

In April 2024, Duke Energy Indiana filed an application with the IURC for a rate increase of $492 million, representing an overall average bill increase of approximately 16.2%, which, if approved, would be added to retail customer bills in two steps, approximately 11.7% in 2025 and approximately 4.5% in 2026. Duke Energy Indiana requested an ROE of 10.5% with an equity ratio of 53%. The rate increase is driven by $1.6 billion in investments made since the last general rate case filed in 2019 in order to reliably serve customers, improve resiliency of the system, and advance environmental sustainability. An evidentiary hearing was completed in September 2024, with briefing continued until October 31, 2024.

In connection with this rate case, a $29 million increase in a regulatory liability associated with certain employee post-retirement benefits was recorded in December 2024. An order for the rate case was issued by the IURC on January 29, 2025, and revised February 3, 2025, which authorized an ROE of 9.75%, an equity ratio of 53% and an annual revenue increase of $296 million. Based on review of these orders, Duke Energy Indiana identified an inconsistency in the calculation of operating revenues before the effect of trackers. On February 7, 2025, Duke Energy Indiana made a compliance filing in accordance with the IURC's findings in its order and addressing the identified inconsistencies. The compliance filing also clarified the annual revenue increase was approximately $385 million. Additionally, on February 18, 2025, one industrial customer submitted a filing requesting the IURC to clarify its revenue allocation in these proceedings. On February 25, 2025, the IURC approved Duke Energy Indiana’s compliance filing subject to refund, pending the outcome of the petition for rehearing. New rates, subject to refund, were implemented February 27, 2025.

Cayuga Combined Cycle CPCN

On February 13, 2025, Duke Energy Indiana filed for a CPCN seeking approval to construct two 1x1 CC natural gas-fired units with a combined winter rating of 1,476 MW. The Cayuga CC Project is proposed to be constructed on the same site as the retiring Cayuga coal-fired steam units with a winter rating of 1,005 MW. The Cayuga CC Project will result in an incremental 471 MW for the Duke Energy Indiana system and will allow Duke Energy Indiana to avoid expected maintenance and environmental compliance costs needed for the coal units to continue operating. The estimated cost of the Cayuga CC project is $2.97 billion, plus AFUDC and project reserves. Duke Energy Indiana has proposed recovery of certain costs of the facility during construction, including AFUDC, through construction work in progress ratemaking through a proposed generation cost adjustment tracker mechanism and estimates an average retail rate impact of approximately 5.4% during construction. Duke Energy Indiana expects CC 1 to be placed in service in 2029 and CC 2 to be placed in service in 2030. An evidentiary hearing is expected in June 2025.

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)	2024		2023		a Return	Period Ends
Regulatory Assets(a)
Accrued pension and OPEB(c)	144		129			(g)
Deferred pipeline integrity costs(c)	101		103			2034
Derivatives – natural gas supply contracts(f)	94		147
Decoupling	77		75		(e)	(b)
Tennessee ARM Deferral	33		20		(e)	(b)
AROs – nuclear and other	29		$	26		(d)
Customer connect project(c)	24		9			2030
Vacation accrual	14		13			2025











Pipeline Integrity Management – Transmission/Distribution	14		—			(b)















Other	49		49		(e)	(b)
Total regulatory assets	579		571
Less: Current portion	158		161
Total noncurrent regulatory assets	$	421	$	410
Regulatory Liabilities(a)
COR regulatory liability(c)	$	539	555			(d)
Net regulatory liability related to income taxes	405		$	433		(b)









Other	80		98		(e)	(b)
Total regulatory liabilities	1,024		1,086
Less: Current portion	68		98
Total noncurrent regulatory liabilities	$	956	$	988

(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.

(d) Recovery over the life of the associated assets.

(e) Certain costs earn/pay a return.

(f) Balance will fluctuate with changes in the market. Current contracts extend into 2031.

(g) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail.

2024 North Carolina Rate Case

In April 2024, Piedmont filed an application with the NCUC for a rate increase for retail customers. In September 2024, Piedmont, the Public Staff and other intervening parties filed an Agreement and Stipulation of Settlement with the NCUC resolving all issues in the general rate case. The major components of the settlement include an overall average effective increase in net annual retail revenues of $88 million in the first year and $10 million of additional revenue after the first year. The settlement includes an ROE of 9.8% with an equity ratio of 52.3% and the addition of a rider mechanism for recovery of pipeline integrity management operations and maintenance expenses. The settlement was subject to the review and approval of the NCUC. The evidentiary hearing concluded in September 2024, and Piedmont implemented revised rates November 1, 2024. The NCUC issued its order approving the settlement as filed on January 7, 2025.

OTHER REGULATORY MATTERS

Potential Coal Plant Retirements

The Subsidiary Registrants periodically file IRPs with their state regulatory commissions. The IRPs provide a view of forecasted energy needs over a long term (10 to 20 years) and resources proposed to meet those needs. The IRPs also include planning assumptions around future retirement dates of aging coal-fired generating facilities.

Duke Energy Carolinas and Duke Energy Progress received an NCUC order on the 2022 Carbon Plan that concluded the projected retirement dates for their coal-fired generating facilities were reasonable for planning purposes and further directed that appropriate steps be taken to optimally retire the coal fleet according to such schedule. In August 2023, Duke Energy Carolinas and Duke Energy Progress filed their 2023 systemwide Carolinas Resource Plan with the NCUC and PSCSC, with a supplemental filing in January 2024 that demonstrated a need for additional resources beyond the set of resources identified by the companies in their initial plan. The NCUC and PSCSC issued orders in 2024 generally approving the resource plan. See the "Other Matters" section of Item 7 Management's Discussion and Analysis for further details on resource plans.

Duke Energy continues to evaluate the retirement date assumptions for all coal-fired generating facilities as changes in energy usage and/or growth and availability of replacement generation could result in different retirement dates of units than their current estimated useful lives. Except as previously discussed related to Duke Energy Kentucky's East Bend plant, rate cases recently filed or approved across all jurisdictions included proposed depreciation rates that approximate earlier retirement dates as outlined in recent IRPs. Duke Energy plans to seek regulatory recovery for amounts that would not be otherwise recovered when any of these assets are retired.