Regulatory Assets And Liabilities

12 Months Ended

Dec. 31, 2024

Regulatory Assets And Liabilities [Line Items]

Regulatory Assets and Liabilities

Note 6. Regulatory Assets and Liabilities

PSE&G prepares its financial statements in accordance with GAAP for regulated utilities as described in Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies. PSE&G has deferred certain costs based on rate orders issued by the BPU or FERC or based on PSE&G’s experience with prior rate proceedings. Most of PSE&G’s Regulatory Assets and Liabilities as of December 31, 2024 are supported by written orders, either explicitly or implicitly through the BPU’s treatment of various cost items. These costs will be recovered and amortized over various future periods.

Regulatory Assets and other investments and costs incurred under our various infrastructure filings and clause mechanisms are subject to prudence reviews and can be disallowed in the future by regulatory authorities. To the extent that collection of any infrastructure or clause mechanism revenue, Regulatory Assets or payments of Regulatory Liabilities is no longer probable, the amounts would be charged or credited to income.

PSE&G had the following Regulatory Assets and Liabilities:

	As of December 31,
	2024		2023
	Millions
Regulatory Assets
Deferred Income Tax Regulatory Assets	$	2,012	$	1,343
Pension and OPEB Costs		1,330		1,427
Green Program Recovery Charges (GPRC)		1,251		827
Conservation Incentive Program (CIP)		261		232
Clean Energy Future-Energy Cloud (CEF-EC)		233		153
Asset Retirement Obligations (ARO)		221		210
Societal Benefits Clause (SBC)		211		155
Manufactured Gas Plant (MGP) Remediation Costs		210		199
Cost of Removal		195		172
New Jersey Clean Energy Program		145		145
COVID-19 Deferral		131		131
2024 Distribution Base Rate Case Regulatory Assets (BRC)		108		—
Remediation Adjustment Charge (RAC) (Other SBC)		102		110
Clean Energy Future-Electric Vehicles (CEF-EV)		51		27
Deferred Storm Costs		—		109
Other		180		190
Total Regulatory Assets		6,641		5,430
Less: Current Regulatory Assets		516		273
Total Noncurrent Regulatory Assets	$	6,125	$	5,157

	As of December 31,
	2024		2023
	Millions
Regulatory Liabilities
Deferred Income Tax Regulatory Liabilities	$	2,619	$	2,245
Gas Costs—Basic Gas Supply Service (BGSS)		145		97
Other		62		82
Total Regulatory Liabilities		2,826		2,424
Less: Current Regulatory Liabilities		555		349
Total Noncurrent Regulatory Liabilities	$	2,271	$	2,075

All Regulatory Assets and Liabilities are excluded from PSE&G’s rate base unless otherwise noted. The Regulatory Assets and Liabilities in the table above are defined as follows:

•ARO: These costs represent the differences between rate-regulated cost of removal accounting and asset retirement accounting under GAAP. These costs will be recovered in future rates as assets are retired.

•BRC: Represents deferred costs, primarily comprised of storm costs incurred in the cleanup of major storms, approved for a five-year recovery pursuant to the 2024 Distribution Base Rate Case Settlement.

•CEF-EC (AMI Meter Deployment): In October 2024, the BPU approved recovery of PSE&G’s CEF-EC capital and operating costs associated with its electric smart meter deployment program. Included in the approved recovery was the return on and of the capital investments in AMI meters and infrastructure, incremental operating costs of the program and stranded costs associated with the accelerated retirement of the non-AMI electric meters.

•CIP: The CIP reduces the impact on electric and gas distribution revenues from changes in sales volumes and demand for most customers. The CIP provides for a true-up of current period revenue as compared to revenue established in PSE&G’s most recent distribution base rate proceeding. Recovery under the CIP is subject to certain limitations, including an actual versus allowed return on equity test and ceilings on customer rate increases.

•CEF-EV (Electric Vehicles): In October 2024, the BPU approved recovery of PSE&G’s CEF-EV capital and operating costs associated with its electric vehicle program, which provides incentives to customers related to EV charger installations. Included in the approved recovery was the return on and of PSE&G’s capital investments and customer incentives, and recovery of incremental operating costs of the program, incurred through November 2024. The BPU also approved annual filings for recovery of future EV investments and costs associated with the program.

•Cost of Removal: PSE&G accrues and collects in rates for the cost of removing, dismantling and disposing of its electric distribution, electric transmission and gas distribution upon retirement. The Regulatory Asset or Liability for non-legally required cost of removal represents the difference between amounts collected in rates and costs actually incurred.

•COVID-19 Deferral: These amounts represent incremental costs related to COVID-19 as approved for recovery by the BPU over a five-year period starting June 1, 2025.

•Deferred Income Tax Regulatory Assets: These amounts relate to deferred income taxes arising from utility operations that have not been included in customer rates relating to depreciation, ITCs and other flow-through items, including the accumulated deferred income taxes related to tax repair and mixed service cost deductions.

As part of PSE&G's 2018 distribution base rate case settlement with the BPU and the establishment of the TAC mechanism, PSE&G agreed to a ten-year flowback to customers of its accumulated deferred income taxes from previously realized tax repair deductions which resulted in the recognition of a $581 million Regulatory Asset and Regulatory Liability as of September 30, 2018. In addition, PSE&G agreed to the current flowback of tax benefits from ongoing tax repair deductions which results in the recording of a Regulatory Asset upon flowback each year.

As part of PSE&G’s 2024 base rate case settlement with the BPU, PSE&G agreed to an additional five-year flowback to customers of its accumulated deferred income taxes from previously realized mixed service cost deductions which resulted in the recognition of a $509 million Regulatory Asset and Regulatory Liability as of September 30, 2024. In addition, PSE&G agreed to the current flowback of tax benefits from ongoing mixed service cost deductions which results in the recording of a Regulatory Asset upon flowback each year.

For the years ended December 31, 2024, 2023 and 2022, PSE&G had provided $81 million, $80 million and $35 million, respectively, in current tax repair flowbacks to customers. The flowback of current mixed service costs commences in January 2025. The recovery and amortization of the tax repair and mixed service cost-related Deferred Income Tax Regulatory Assets is being recovered through the TAC regulatory mechanism, with the mixed service cost component commencing recovery in January 2025.

•Deferred Income Tax Regulatory Liabilities: These liabilities primarily relate to amounts due to customers for excess deferred income taxes as a result of the reduction in the federal corporate income tax rate provided in the Tax Cuts and Jobs Act of 2017, and accumulated deferred income taxes from previously realized distribution-related tax repair and mixed service cost deductions. As part of its settlement with its regulators, PSE&G agreed to refund the excess deferred income taxes as follows:

•Protected distribution-related excess deferred income taxes are being refunded to customers over the remaining useful lives of distribution property, plant and equipment through PSE&G’s TAC mechanism. As of December 31, 2024, the balance remaining to be flowed back to customers was approximately $840 million.

•Previously realized distribution-related tax repair deductions are being refunded to customers over ten years through PSE&G’s TAC mechanism. As of December 31, 2024, the balance remaining to be flowed back to customers was approximately $310 million through 2028.

•Previously realized distribution-related mixed service cost deductions are being refunded to customers over five years through PSE&G’s TAC mechanism. As of December 31, 2024, the balance to be flowed back to customers was approximately $509 million through 2029.

•Protected transmission-related excess deferred income taxes are being refunded to customers over the remaining useful life of transmission property, plant and equipment through PSE&G’s transmission formula rate mechanism. As of December 31, 2024, the balance remaining to be flowed back to customers was approximately $928 million.

•Electric Energy Costs—BGS: These costs represent the over or under recovered amounts associated with BGS, as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for electric customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. Over or under recovered balances with interest are returned or recovered through monthly filings.

•Gas Costs—BGSS: These costs represent the over or under recovered amounts associated with BGSS, as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for gas customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. Over or under collected balances are returned or recovered through an annual filing. Interest is accrued only on over recovered balances.

•GPRC: PSE&G files an annual GPRC petition with the BPU for recovery of amounts associated with the BPU Board-approved energy efficiency (EE) and solar (renewable) energy (RE) programs that include a return on and of investments and capital assets, as well as recovery for deferred expenses and incremental costs. The GPRC investment program component is recovered over the lives of the underlying investments and capital assets which range from five to twenty years.

The approved GPRC components receiving recovery for the return on and of investments include: Carbon Abatement, Energy Efficiency Economic Stimulus Program (EEE), EEE Extension Program, EEE Extension II Program, Solar Generation Investment Program (Solar 4 All®), Solar 4 All® Extension, Solar 4 All® Extension II, Solar Loan II Program, Solar Loan III Program, EE 2017 Program, Clean Energy Future–Energy Efficiency (CEF-EE) and CEF-EE-II.

In addition, the GPRC components receiving cost recovery for deferred expenses include: the Transition Renewable Energy Certificate Program, Community Solar Energy Program and the Successor Solar Incentive Program.

The Regulatory Asset balances represent the deferred investment and related undercollected balances with a Regulatory Liability recorded for any overrecovered balance. Interest is accrued monthly on any over-or under- recovered balances. Amortization of deferred investment and expenses are recorded in O&M expense. The capital asset portion of GPRC investments primarily in company-owned solar facilities is included in Property, Plant and Equipment, with depreciation recorded in Depreciation and Amortization Expense.

•MGP Remediation Costs: Represents the low end of the range for the remaining environmental investigation and remediation program cleanup costs for MGPs that are probable of recovery in future rates. Once these costs are incurred, they are recovered through the RAC in the SBC over a seven year period with interest.

•New Jersey Clean Energy Program: The BPU approved future funding requirements for EE and RE Programs. The BPU funding requirements are recovered through the SBC.

•Pension and OPEB Costs: PSE&G records the unrecognized costs for defined benefit pension and other OPEB plans on the balance sheet as Regulatory Assets pursuant to the adoption of accounting guidance for employers’ defined benefit pension and OPEB plans, and relevant BPU orders. These costs represent net actuarial gains or losses and prior service costs which have not been expensed. These costs are amortized and recovered in future rates.

•RAC (Other SBC): Costs incurred to clean up MGPs which are recovered over seven years with interest through an annual filing.

•SBC: The SBC, as authorized by the BPU and the New Jersey Electric Discount and Energy Competition Act, includes costs related to PSE&G’s electric and gas business as follows: (1) the Universal Service Fund; (2) EE & RE Programs; (3) Electric bad debt expense; and (4) the RAC for incurred MGP remediation expenditures. Over or under recovered balances with interest are to be returned or recovered through an annual filing.

Significant 2024 regulatory orders received and currently pending rate filings with the BPU or FERC by PSE&G are as follows:

•Electric and Gas Distribution Base Rate Case Filings – In October 2024, the BPU issued an Order approving the settlement of PSE&G’s distribution base rate case with new rates effective October 15, 2024. The Order provides for a $17.8 billion rate base, a 9.6% return on equity for PSE&G’s distribution business and a 55% equity component of its capitalization structure. The settlement results in a net increase in annual revenues of approximately $505 million, comprised of a $711 million increase in base revenues, offset by the return of tax benefits of approximately $206 million.

The return of tax benefits includes the flowback to customers of excess accumulated deferred income taxes and the flowback of previously recovered deferred income taxes and current tax repair deductions under the Tax Adjustment Credit (TAC) mechanism approved by the BPU in PSE&G’s 2018 distribution base rate case. The settlement approves an additional flowback of previously recovered deferred income taxes and current mixed service cost deductions. As a result of the approval to flowback previously recovered deferred income taxes related to mixed service costs, PSE&G recognized a $509 million regulatory liability and a corresponding regulatory asset as of September 30, 2024.

The settlement also approved the recovery of regulatory assets primarily associated with deferred storm costs, PSE&G’s electric vehicle charging program (CEF-EV) and electric meter AMI deployment program (CEF-EC), including stranded costs associated with the early retirement of legacy meters.

In addition, the Order approved mechanisms associated with the recovery of future storm costs as well as the recovery of annual pension and OPEB expenses beginning January 1, 2025.

•BGSS—In April 2024, the BPU gave final approval to PSE&G’s BGSS rate of approximately 40 cents per therm.

In September 2024, the BPU approved on a provisional basis, PSE&G's request to decrease its BGSS rate to approximately 33 cents per therm, with the new rate effective October 1, 2024.

•CIP—In April 2024, the BPU gave final approval to provisional gas CIP rates which were effective October 1, 2023.

In September 2024, BPU approved on a provisional basis, PSE&G's annual gas CIP petition to recover estimated deficient gas revenues of approximately $107 million based on the 12-month period ended September 30, 2024 with new rates effective October 1, 2024.

In February 2025, the BPU gave final approval for PSE&G’s updated electric CIP petition to recover approximately $96 million of deficient electric revenues over two years that resulted from the 12-month period ended May 31, 2024, with new rates effective August 1, 2024.

In February 2025, PSE&G filed its 2025 annual electric CIP petition seeking BPU approval to recover estimated deficient electric revenues of approximately $65 Million based on the 12-month period ending May 31, 2025, with new rates proposed to be effective June 1, 2025. This matter is pending.

•COVID-19 Deferral—In June 2024, the BPU approved recovery of PSE&G’s previously deferred incremental COVID-19 costs over a five-year period, effective June 1, 2025. PSE&G has deferred approximately $131 million as a Regulatory Asset for its net incremental costs, including $68 million for incremental gas bad debt expense associated with customer accounts receivable.

•Energy Strong II—In April 2024, the BPU approved an annualized increase in electric revenue requirement of $12 million, with rates effective May 1, 2024. The approved electric revenue increase represents the return of and on actual Energy Strong II investments placed in service through December 31, 2023.

•Gas System Modernization Program II Extension (GSMP II Ext) – In February 2025, PSE&G filed its initial GSMP II Ext cost recovery petition seeking BPU approval to recover in gas base rates an annual revenue increase of $53 million effective August 1, 2025. This filing requests the return on and of investment for GSMP II Ext gas investments expected to be placed in service through April 30, 2025. This matter is pending.

•Green Program Recovery Charges (GPRC)—In May 2024, the BPU approved PSE&G’s petition for a second extension of its Clean Energy Future (CEF)-EE subprogram investment (a component of GPRC) by approximately $300 million covering a commitment period from July 2024 through December 2024.

In June 2024, the BPU approved PSE&G’s updated 2023 GPRC cost recovery petition for $49 million and $15 million in annual electric and gas revenues, respectively.

In June 2024, PSE&G filed its 2024 GPRC cost recovery petition requesting BPU approval for recovery of increases of $68 million and $24 million in annual electric and gas revenues, respectively. This matter is pending.

In October 2024, the BPU approved PSE&G’s CEF-EE II investment program as a new component of GPRC. The Order authorizes a total spend of approximately $2.9 billion for energy efficiency projects committed between January 1, 2025 through June 30, 2027, and completed over an expected six-year period. The Order approving CEF-EE II will result in an annual increase in gas revenues of approximately $3 million, effective January 1, 2025.

•Infrastructure Advancement Program (IAP)—In May 2024, the BPU approved PSE&G's updated IAP cost recovery petition seeking BPU approval to recover in electric base rates an annual revenue increase of $5 million. This increase represents the return of and on investment for IAP electric investments in service through January 31, 2024. New rates were effective June 1, 2024.

In February 2025, PSE&G filed an updated IAP cost recovery petition seeking BPU approval to recover in electric and gas base rates an annual revenue increase of $6 million and $3 million, respectively, effective May 1, 2025. This increase represents the return of and on investment for IAP electric investments in service through January 31, 2025. This matter is pending.

•RAC— In January 2025, the BPU approved PSE&G’s RAC 30 petition approving recovery of approximately $56 million of net MGP expenditures incurred from August 1, 2021 through July 31, 2022, with new rates effective February 15, 2025.

•SBC and Non-Utility Generation Charge (NGC) —In March 2024, the BPU approved annual increases in electric and gas SBC revenues of $27 million and $32 million, respectively, pursuant to PSE&G’s 2023 SBC filing to recover electric and gas costs incurred under the Energy Efficiency & Renewable Energy and Social Programs components of the SBC. As part of the

COVID-19 Order approved by the BPU in June 2024, PSE&G will commence recovery of $78 million electric bad debt expense deferred within the Social Programs component over a five-year period effective with the approval of PSE&G’s next SBC filing.

In December 2024, PSE&G filed a petition to decrease its annual electric SBC and NGC rates by approximately $3 million and increase its annual SBC gas rate by $38 million based on PSE&G’s actual collections and expenses through November 30, 2024, and its projected collections and expenses through May 31, 2026 under the NGC and the Energy Efficiency & Renewable Energy and Social Programs components of the SBC. This petition includes the commencement of recovery of the previously deferred electric bad debt expense over a five-year period via the Social Programs component of the SBC.

•Tax Adjustment Credit (TAC)—As part of PSE&G’s distribution rate case settlement, PSE&G agreed to change the electric and gas TAC rates effectuating an annual revenue decrease of approximately $99 million and $107 million, respectively, effective October 15, 2024. The revenue decrease is primarily the result of higher TAC credits to customers due to the flow-back of additional tax benefits related to mixed service costs.

In February 2024, the BPU approved PSE&G’s 2023 TAC filing to increase annual electric and gas revenues by approximately $61 million and $40 million, respectively, with new rates effective March 1, 2024.

•Transmission Formula Rates— In June 2024, in accordance with its transmission formula rate protocols, PSE&G filed with the FERC its 2023 true-up adjustment pertaining to its transmission formula rates in effect for calendar year 2023, as established by its 2023 annual forecast filing. The June 2024 true-up filing resulted in an approximate $12 million increase in the 2023 annual revenue requirement from the revenue requirement numbers contained in the forecast filing. PSE&G had previously recognized the majority of the increased revenue requirement in 2023.

In October 2024, in accordance with its transmission formula rate protocols, PSE&G submitted with FERC its formula rate annual update for 2025. This 2025 update sets forth PSE&G’s annual transmission revenue requirement for the period commencing January 1, 2025 through December 31, 2025, which will result in a $64 million increase in its annual transmission revenue, subject to true-up.

•ZEC Program—In August 2024, the BPU approved the final ZEC price of $9.95 per MWh for the Energy Year ended May 31, 2024. As a result, PSE&G purchased approximately $166 million of ZECs including interest, from the eligible nuclear plants selected by the BPU with the final payment made in August 2024. As total customer collections equaled the required ZEC payments, there were no over-collected revenues from customers for the Energy Year ended May 31, 2024.

Public Service Electric and Gas Company

Regulatory Assets And Liabilities [Line Items]

Regulatory Assets and Liabilities

Note 6. Regulatory Assets and Liabilities

PSE&G prepares its financial statements in accordance with GAAP for regulated utilities as described in Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies. PSE&G has deferred certain costs based on rate orders issued by the BPU or FERC or based on PSE&G’s experience with prior rate proceedings. Most of PSE&G’s Regulatory Assets and Liabilities as of December 31, 2024 are supported by written orders, either explicitly or implicitly through the BPU’s treatment of various cost items. These costs will be recovered and amortized over various future periods.

Regulatory Assets and other investments and costs incurred under our various infrastructure filings and clause mechanisms are subject to prudence reviews and can be disallowed in the future by regulatory authorities. To the extent that collection of any infrastructure or clause mechanism revenue, Regulatory Assets or payments of Regulatory Liabilities is no longer probable, the amounts would be charged or credited to income.

PSE&G had the following Regulatory Assets and Liabilities:

	As of December 31,
	2024		2023
	Millions
Regulatory Assets
Deferred Income Tax Regulatory Assets	$	2,012	$	1,343
Pension and OPEB Costs		1,330		1,427
Green Program Recovery Charges (GPRC)		1,251		827
Conservation Incentive Program (CIP)		261		232
Clean Energy Future-Energy Cloud (CEF-EC)		233		153
Asset Retirement Obligations (ARO)		221		210
Societal Benefits Clause (SBC)		211		155
Manufactured Gas Plant (MGP) Remediation Costs		210		199
Cost of Removal		195		172
New Jersey Clean Energy Program		145		145
COVID-19 Deferral		131		131
2024 Distribution Base Rate Case Regulatory Assets (BRC)		108		—
Remediation Adjustment Charge (RAC) (Other SBC)		102		110
Clean Energy Future-Electric Vehicles (CEF-EV)		51		27
Deferred Storm Costs		—		109
Other		180		190
Total Regulatory Assets		6,641		5,430
Less: Current Regulatory Assets		516		273
Total Noncurrent Regulatory Assets	$	6,125	$	5,157

	As of December 31,
	2024		2023
	Millions
Regulatory Liabilities
Deferred Income Tax Regulatory Liabilities	$	2,619	$	2,245
Gas Costs—Basic Gas Supply Service (BGSS)		145		97
Other		62		82
Total Regulatory Liabilities		2,826		2,424
Less: Current Regulatory Liabilities		555		349
Total Noncurrent Regulatory Liabilities	$	2,271	$	2,075

All Regulatory Assets and Liabilities are excluded from PSE&G’s rate base unless otherwise noted. The Regulatory Assets and Liabilities in the table above are defined as follows:

•ARO: These costs represent the differences between rate-regulated cost of removal accounting and asset retirement accounting under GAAP. These costs will be recovered in future rates as assets are retired.

•BRC: Represents deferred costs, primarily comprised of storm costs incurred in the cleanup of major storms, approved for a five-year recovery pursuant to the 2024 Distribution Base Rate Case Settlement.

•CEF-EC (AMI Meter Deployment): In October 2024, the BPU approved recovery of PSE&G’s CEF-EC capital and operating costs associated with its electric smart meter deployment program. Included in the approved recovery was the return on and of the capital investments in AMI meters and infrastructure, incremental operating costs of the program and stranded costs associated with the accelerated retirement of the non-AMI electric meters.

•CIP: The CIP reduces the impact on electric and gas distribution revenues from changes in sales volumes and demand for most customers. The CIP provides for a true-up of current period revenue as compared to revenue established in PSE&G’s most recent distribution base rate proceeding. Recovery under the CIP is subject to certain limitations, including an actual versus allowed return on equity test and ceilings on customer rate increases.

•CEF-EV (Electric Vehicles): In October 2024, the BPU approved recovery of PSE&G’s CEF-EV capital and operating costs associated with its electric vehicle program, which provides incentives to customers related to EV charger installations. Included in the approved recovery was the return on and of PSE&G’s capital investments and customer incentives, and recovery of incremental operating costs of the program, incurred through November 2024. The BPU also approved annual filings for recovery of future EV investments and costs associated with the program.

•Cost of Removal: PSE&G accrues and collects in rates for the cost of removing, dismantling and disposing of its electric distribution, electric transmission and gas distribution upon retirement. The Regulatory Asset or Liability for non-legally required cost of removal represents the difference between amounts collected in rates and costs actually incurred.

•COVID-19 Deferral: These amounts represent incremental costs related to COVID-19 as approved for recovery by the BPU over a five-year period starting June 1, 2025.

•Deferred Income Tax Regulatory Assets: These amounts relate to deferred income taxes arising from utility operations that have not been included in customer rates relating to depreciation, ITCs and other flow-through items, including the accumulated deferred income taxes related to tax repair and mixed service cost deductions.

As part of PSE&G's 2018 distribution base rate case settlement with the BPU and the establishment of the TAC mechanism, PSE&G agreed to a ten-year flowback to customers of its accumulated deferred income taxes from previously realized tax repair deductions which resulted in the recognition of a $581 million Regulatory Asset and Regulatory Liability as of September 30, 2018. In addition, PSE&G agreed to the current flowback of tax benefits from ongoing tax repair deductions which results in the recording of a Regulatory Asset upon flowback each year.

As part of PSE&G’s 2024 base rate case settlement with the BPU, PSE&G agreed to an additional five-year flowback to customers of its accumulated deferred income taxes from previously realized mixed service cost deductions which resulted in the recognition of a $509 million Regulatory Asset and Regulatory Liability as of September 30, 2024. In addition, PSE&G agreed to the current flowback of tax benefits from ongoing mixed service cost deductions which results in the recording of a Regulatory Asset upon flowback each year.

For the years ended December 31, 2024, 2023 and 2022, PSE&G had provided $81 million, $80 million and $35 million, respectively, in current tax repair flowbacks to customers. The flowback of current mixed service costs commences in January 2025. The recovery and amortization of the tax repair and mixed service cost-related Deferred Income Tax Regulatory Assets is being recovered through the TAC regulatory mechanism, with the mixed service cost component commencing recovery in January 2025.

•Deferred Income Tax Regulatory Liabilities: These liabilities primarily relate to amounts due to customers for excess deferred income taxes as a result of the reduction in the federal corporate income tax rate provided in the Tax Cuts and Jobs Act of 2017, and accumulated deferred income taxes from previously realized distribution-related tax repair and mixed service cost deductions. As part of its settlement with its regulators, PSE&G agreed to refund the excess deferred income taxes as follows:

•Protected distribution-related excess deferred income taxes are being refunded to customers over the remaining useful lives of distribution property, plant and equipment through PSE&G’s TAC mechanism. As of December 31, 2024, the balance remaining to be flowed back to customers was approximately $840 million.

•Previously realized distribution-related tax repair deductions are being refunded to customers over ten years through PSE&G’s TAC mechanism. As of December 31, 2024, the balance remaining to be flowed back to customers was approximately $310 million through 2028.

•Previously realized distribution-related mixed service cost deductions are being refunded to customers over five years through PSE&G’s TAC mechanism. As of December 31, 2024, the balance to be flowed back to customers was approximately $509 million through 2029.

•Protected transmission-related excess deferred income taxes are being refunded to customers over the remaining useful life of transmission property, plant and equipment through PSE&G’s transmission formula rate mechanism. As of December 31, 2024, the balance remaining to be flowed back to customers was approximately $928 million.

•Electric Energy Costs—BGS: These costs represent the over or under recovered amounts associated with BGS, as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for electric customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. Over or under recovered balances with interest are returned or recovered through monthly filings.

•Gas Costs—BGSS: These costs represent the over or under recovered amounts associated with BGSS, as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for gas customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. Over or under collected balances are returned or recovered through an annual filing. Interest is accrued only on over recovered balances.

•GPRC: PSE&G files an annual GPRC petition with the BPU for recovery of amounts associated with the BPU Board-approved energy efficiency (EE) and solar (renewable) energy (RE) programs that include a return on and of investments and capital assets, as well as recovery for deferred expenses and incremental costs. The GPRC investment program component is recovered over the lives of the underlying investments and capital assets which range from five to twenty years.

The approved GPRC components receiving recovery for the return on and of investments include: Carbon Abatement, Energy Efficiency Economic Stimulus Program (EEE), EEE Extension Program, EEE Extension II Program, Solar Generation Investment Program (Solar 4 All®), Solar 4 All® Extension, Solar 4 All® Extension II, Solar Loan II Program, Solar Loan III Program, EE 2017 Program, Clean Energy Future–Energy Efficiency (CEF-EE) and CEF-EE-II.

In addition, the GPRC components receiving cost recovery for deferred expenses include: the Transition Renewable Energy Certificate Program, Community Solar Energy Program and the Successor Solar Incentive Program.

The Regulatory Asset balances represent the deferred investment and related undercollected balances with a Regulatory Liability recorded for any overrecovered balance. Interest is accrued monthly on any over-or under- recovered balances. Amortization of deferred investment and expenses are recorded in O&M expense. The capital asset portion of GPRC investments primarily in company-owned solar facilities is included in Property, Plant and Equipment, with depreciation recorded in Depreciation and Amortization Expense.

•MGP Remediation Costs: Represents the low end of the range for the remaining environmental investigation and remediation program cleanup costs for MGPs that are probable of recovery in future rates. Once these costs are incurred, they are recovered through the RAC in the SBC over a seven year period with interest.

•New Jersey Clean Energy Program: The BPU approved future funding requirements for EE and RE Programs. The BPU funding requirements are recovered through the SBC.

•Pension and OPEB Costs: PSE&G records the unrecognized costs for defined benefit pension and other OPEB plans on the balance sheet as Regulatory Assets pursuant to the adoption of accounting guidance for employers’ defined benefit pension and OPEB plans, and relevant BPU orders. These costs represent net actuarial gains or losses and prior service costs which have not been expensed. These costs are amortized and recovered in future rates.

•RAC (Other SBC): Costs incurred to clean up MGPs which are recovered over seven years with interest through an annual filing.

•SBC: The SBC, as authorized by the BPU and the New Jersey Electric Discount and Energy Competition Act, includes costs related to PSE&G’s electric and gas business as follows: (1) the Universal Service Fund; (2) EE & RE Programs; (3) Electric bad debt expense; and (4) the RAC for incurred MGP remediation expenditures. Over or under recovered balances with interest are to be returned or recovered through an annual filing.

Significant 2024 regulatory orders received and currently pending rate filings with the BPU or FERC by PSE&G are as follows:

•Electric and Gas Distribution Base Rate Case Filings – In October 2024, the BPU issued an Order approving the settlement of PSE&G’s distribution base rate case with new rates effective October 15, 2024. The Order provides for a $17.8 billion rate base, a 9.6% return on equity for PSE&G’s distribution business and a 55% equity component of its capitalization structure. The settlement results in a net increase in annual revenues of approximately $505 million, comprised of a $711 million increase in base revenues, offset by the return of tax benefits of approximately $206 million.

The return of tax benefits includes the flowback to customers of excess accumulated deferred income taxes and the flowback of previously recovered deferred income taxes and current tax repair deductions under the Tax Adjustment Credit (TAC) mechanism approved by the BPU in PSE&G’s 2018 distribution base rate case. The settlement approves an additional flowback of previously recovered deferred income taxes and current mixed service cost deductions. As a result of the approval to flowback previously recovered deferred income taxes related to mixed service costs, PSE&G recognized a $509 million regulatory liability and a corresponding regulatory asset as of September 30, 2024.

The settlement also approved the recovery of regulatory assets primarily associated with deferred storm costs, PSE&G’s electric vehicle charging program (CEF-EV) and electric meter AMI deployment program (CEF-EC), including stranded costs associated with the early retirement of legacy meters.

In addition, the Order approved mechanisms associated with the recovery of future storm costs as well as the recovery of annual pension and OPEB expenses beginning January 1, 2025.

•BGSS—In April 2024, the BPU gave final approval to PSE&G’s BGSS rate of approximately 40 cents per therm.

In September 2024, the BPU approved on a provisional basis, PSE&G's request to decrease its BGSS rate to approximately 33 cents per therm, with the new rate effective October 1, 2024.

•CIP—In April 2024, the BPU gave final approval to provisional gas CIP rates which were effective October 1, 2023.

In September 2024, BPU approved on a provisional basis, PSE&G's annual gas CIP petition to recover estimated deficient gas revenues of approximately $107 million based on the 12-month period ended September 30, 2024 with new rates effective October 1, 2024.

In February 2025, the BPU gave final approval for PSE&G’s updated electric CIP petition to recover approximately $96 million of deficient electric revenues over two years that resulted from the 12-month period ended May 31, 2024, with new rates effective August 1, 2024.

In February 2025, PSE&G filed its 2025 annual electric CIP petition seeking BPU approval to recover estimated deficient electric revenues of approximately $65 Million based on the 12-month period ending May 31, 2025, with new rates proposed to be effective June 1, 2025. This matter is pending.

•COVID-19 Deferral—In June 2024, the BPU approved recovery of PSE&G’s previously deferred incremental COVID-19 costs over a five-year period, effective June 1, 2025. PSE&G has deferred approximately $131 million as a Regulatory Asset for its net incremental costs, including $68 million for incremental gas bad debt expense associated with customer accounts receivable.

•Energy Strong II—In April 2024, the BPU approved an annualized increase in electric revenue requirement of $12 million, with rates effective May 1, 2024. The approved electric revenue increase represents the return of and on actual Energy Strong II investments placed in service through December 31, 2023.

•Gas System Modernization Program II Extension (GSMP II Ext) – In February 2025, PSE&G filed its initial GSMP II Ext cost recovery petition seeking BPU approval to recover in gas base rates an annual revenue increase of $53 million effective August 1, 2025. This filing requests the return on and of investment for GSMP II Ext gas investments expected to be placed in service through April 30, 2025. This matter is pending.

•Green Program Recovery Charges (GPRC)—In May 2024, the BPU approved PSE&G’s petition for a second extension of its Clean Energy Future (CEF)-EE subprogram investment (a component of GPRC) by approximately $300 million covering a commitment period from July 2024 through December 2024.

In June 2024, the BPU approved PSE&G’s updated 2023 GPRC cost recovery petition for $49 million and $15 million in annual electric and gas revenues, respectively.

In June 2024, PSE&G filed its 2024 GPRC cost recovery petition requesting BPU approval for recovery of increases of $68 million and $24 million in annual electric and gas revenues, respectively. This matter is pending.

In October 2024, the BPU approved PSE&G’s CEF-EE II investment program as a new component of GPRC. The Order authorizes a total spend of approximately $2.9 billion for energy efficiency projects committed between January 1, 2025 through June 30, 2027, and completed over an expected six-year period. The Order approving CEF-EE II will result in an annual increase in gas revenues of approximately $3 million, effective January 1, 2025.

•Infrastructure Advancement Program (IAP)—In May 2024, the BPU approved PSE&G's updated IAP cost recovery petition seeking BPU approval to recover in electric base rates an annual revenue increase of $5 million. This increase represents the return of and on investment for IAP electric investments in service through January 31, 2024. New rates were effective June 1, 2024.

In February 2025, PSE&G filed an updated IAP cost recovery petition seeking BPU approval to recover in electric and gas base rates an annual revenue increase of $6 million and $3 million, respectively, effective May 1, 2025. This increase represents the return of and on investment for IAP electric investments in service through January 31, 2025. This matter is pending.

•RAC— In January 2025, the BPU approved PSE&G’s RAC 30 petition approving recovery of approximately $56 million of net MGP expenditures incurred from August 1, 2021 through July 31, 2022, with new rates effective February 15, 2025.

•SBC and Non-Utility Generation Charge (NGC) —In March 2024, the BPU approved annual increases in electric and gas SBC revenues of $27 million and $32 million, respectively, pursuant to PSE&G’s 2023 SBC filing to recover electric and gas costs incurred under the Energy Efficiency & Renewable Energy and Social Programs components of the SBC. As part of the

COVID-19 Order approved by the BPU in June 2024, PSE&G will commence recovery of $78 million electric bad debt expense deferred within the Social Programs component over a five-year period effective with the approval of PSE&G’s next SBC filing.

In December 2024, PSE&G filed a petition to decrease its annual electric SBC and NGC rates by approximately $3 million and increase its annual SBC gas rate by $38 million based on PSE&G’s actual collections and expenses through November 30, 2024, and its projected collections and expenses through May 31, 2026 under the NGC and the Energy Efficiency & Renewable Energy and Social Programs components of the SBC. This petition includes the commencement of recovery of the previously deferred electric bad debt expense over a five-year period via the Social Programs component of the SBC.

•Tax Adjustment Credit (TAC)—As part of PSE&G’s distribution rate case settlement, PSE&G agreed to change the electric and gas TAC rates effectuating an annual revenue decrease of approximately $99 million and $107 million, respectively, effective October 15, 2024. The revenue decrease is primarily the result of higher TAC credits to customers due to the flow-back of additional tax benefits related to mixed service costs.

In February 2024, the BPU approved PSE&G’s 2023 TAC filing to increase annual electric and gas revenues by approximately $61 million and $40 million, respectively, with new rates effective March 1, 2024.

•Transmission Formula Rates— In June 2024, in accordance with its transmission formula rate protocols, PSE&G filed with the FERC its 2023 true-up adjustment pertaining to its transmission formula rates in effect for calendar year 2023, as established by its 2023 annual forecast filing. The June 2024 true-up filing resulted in an approximate $12 million increase in the 2023 annual revenue requirement from the revenue requirement numbers contained in the forecast filing. PSE&G had previously recognized the majority of the increased revenue requirement in 2023.

In October 2024, in accordance with its transmission formula rate protocols, PSE&G submitted with FERC its formula rate annual update for 2025. This 2025 update sets forth PSE&G’s annual transmission revenue requirement for the period commencing January 1, 2025 through December 31, 2025, which will result in a $64 million increase in its annual transmission revenue, subject to true-up.

•ZEC Program—In August 2024, the BPU approved the final ZEC price of $9.95 per MWh for the Energy Year ended May 31, 2024. As a result, PSE&G purchased approximately $166 million of ZECs including interest, from the eligible nuclear plants selected by the BPU with the final payment made in August 2024. As total customer collections equaled the required ZEC payments, there were no over-collected revenues from customers for the Energy Year ended May 31, 2024.