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Regulatory Assets And Liabilities | 12 Months Ended
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Dec. 31, 2021
Regulatory Assets And Liabilities [Line Items] |
Regulatory Assets and Liabilities | 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, 2021 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, |
|  |  | 2021 |  | 2020 |
|  |  | Millions |
| Regulatory Assets |  |  |  |  |
| Current |  |  |  |  |
| New Jersey Clean Energy Program |  | $ | 146 |  |  | $ | 143 |  |
| Electric Energy Costs—Basic Generation Service (BGS) |  | 67 |  |  | 60 |  |
| 2018 Distribution Base Rate Case Regulatory Assets (BRC) |  | 56 |  |  | 56 |  |
| Tax Adjustment Credit (TAC) |  | 44 |  |  | — |  |
| Conservation Incentive Program (CIP) |  | 36 |  |  | — |  |
| Formula Rate True-up |  | 13 |  |  | 23 |  |
| SBC |  | — |  |  | 82 |  |
| Other |  | 2 |  |  | 5 |  |
| Total Current Regulatory Assets |  | 364 |  |  | 369 |  |
| Noncurrent |  |  |  |  |
| Deferred Income Tax Regulatory Assets |  | $ | 1,064 |  |  | $ | 1,014 |  |
| Pension and OPEB Costs |  | 1,043 |  |  | 1,489 |  |
| Manufactured Gas Plant (MGP) Remediation Costs |  | 220 |  |  | 320 |  |
| Green Program Recovery Charges (GPRC) |  | 211 |  |  | 139 |  |
| Asset Retirement Obligation |  | 191 |  |  | 184 |  |
| Electric Transmission and Gas Cost of Removal |  | 174 |  |  | 189 |  |
| Remediation Adjustment Charge (RAC) (Other SBC) |  | 156 |  |  | 134 |  |
| SBC (Electric Bad Debt) |  | 139 |  |  | — |  |
| COVID-19 Deferral |  | 116 |  |  | 51 |  |
| Deferred Storm Costs |  | 109 |  |  | 99 |  |
| BRC |  | 47 |  |  | 103 |  |
| Other |  | 135 |  |  | 150 |  |
| Total Noncurrent Regulatory Assets |  | 3,605 |  |  | 3,872 |  |
| Total Regulatory Assets |  | $ | 3,969 |  |  | $ | 4,241 |  |
|  |  | As of December 31, |
|  |  | 2021 |  | 2020 |
|  |  | Millions |
| Regulatory Liabilities |  |  |  |  |
| Current |  |  |  |  |
| Deferred Income Tax Regulatory Liabilities |  | $ | 288 |  |  | $ | 250 |  |
| Formula Rate True-up |  | 42 |  |  | — |  |
| GPRC |  | 19 |  |  | 1 |  |
| ZEC Liability |  | 11 |  |  | 17 |  |
| Gas Costs—BGSS |  | 5 |  |  | 20 |  |
| Other |  | 23 |  |  | 6 |  |
| Total Current Regulatory Liabilities |  | 388 |  |  | 294 |  |
| Noncurrent |  |  |  |  |
| Deferred Income Tax Regulatory Liabilities |  | $ | 2,443 |  |  | $ | 2,670 |  |
| Other |  | 54 |  |  | 37 |  |
| Total Noncurrent Regulatory Liabilities |  | 2,497 |  |  | 2,707 |  |
| Total Regulatory Liabilities |  | $ | 2,885 |  |  | $ | 3,001 |  |
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: •Asset Retirement Obligation: 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 from 2010 through 2018, which are being amortized over five years pursuant to the 2018 Distribution Base Rate Case Settlement. •CIP: The CIP reduces the impact on distribution revenues from changes in sales volumes and demand for most customers. The CIP, which is calculated annually, 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 (ROE) test and ceilings on customer rate increases. The CIP became effective in June 2021 for electric revenues and October 2021 for gas revenues. The gas CIP replaced the Weather Normalization Clause. •COVID-19 Deferral: These amounts represent incremental costs related to COVID-19 as authorized for deferral in an order issued by the BPU to all New Jersey regulated utilities in July 2020. The BPU authorized such utilities to create a COVID-19-related Regulatory Asset by deferring on their books and records the prudently incurred incremental costs related to COVID-19 during the Regulatory Asset period, beginning on March 9, 2020 through September 30, 2021, or 60 days after the New Jersey governor determines that the Public Health Emergency is no longer in effect, or in the absence of such a determination, 60 days from the time the Public Health Emergency automatically terminates by law, whichever is later. Deferred costs are to be offset by any federal or state assistance that the utility may receive as a direct result of the COVID-19 pandemic. Utilities must file quarterly reports of the costs incurred and offsets. Each participating utility must file a petition documenting its prudently incurred incremental COVID-19 costs by December 31, 2021, or within 60 days of the close of the Regulatory Asset period as described above, whichever is later. In September 2021, the BPU extended the deferral period to December 31, 2022. Any potential rate recovery, including any prudency determinations and the appropriate period of recovery, will be addressed through that filing, or in the alternative, the utility may request that the BPU defer consideration of rate recovery for a future base rate case. •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 flowback to customers of accumulated deferred income taxes related to tax repair deductions. As part of its base rate case settlement with the BPU and the establishment of the TAC mechanism in 2018, 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 as realized which results in the recording of a Regulatory Asset upon flowback. For the years ended December 31, 2021, 2020 and 2019, PSE&G had provided $22 million, $31 million and $58 million, respectively, in current tax repair flowbacks to customers. The recovery and amortization of the tax repair-related Deferred Income Tax Regulatory Assets will be determined in PSE&G’s subsequent base rate cases. •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 (Tax Act), and accumulated deferred income taxes from previously realized distribution-related tax repair deductions. As part of its settlement with its regulators, PSE&G agreed to refund the excess deferred income taxes as follows: •Unprotected distribution-related excess deferred income taxes are being refunded to customers over five years through PSE&G’s TAC mechanism as approved in its 2018 distribution base rate proceeding. As of December 31, 2021, the balance remaining to be flowed back to customers was approximately $371 million with the remaining flowback period through 2024. •Protected distribution-related excess deferred income taxes are being refunded to customers over the remaining useful life of distribution property, plant and equipment through PSE&G’s TAC mechanism. As of December 31, 2021, the balance remaining to be flowed back to customers was approximately $905 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, 2021, the balance remaining to be flowed back to customers was approximately $462 million through 2028. •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, 2021, the balance remaining to be flowed back to customers was approximately $939 million. •Unprotected transmission-related deferred income taxes were fully refunded to customers in 2019 and 2020. •Deferred Storm Costs: Incremental costs incurred in the restoration and related costs from major storms in 2019, 2020 and 2021 for which PSE&G will seek recovery in its next base rate proceeding. •Electric and Gas Cost of Removal: PSE&G accrues and collects in rates for the cost of removing, dismantling and disposing of its T&D assets 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. •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. •Formula Rate True-Up: PSE&G’s transmission revenues are earned under a FERC-approved annual formula rate mechanism which provides for an annual filing of an estimated revenue requirement with rates effective January 1 of each year and a true-up to that estimate based on actual revenue requirements. •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: This amount represents costs of the over or under collected balances associated with various Energy Efficiency and Renewable Energy (EE & RE) Programs. PSE&G files annually with the BPU for recovery of amounts that include a return on and of its investment over the lives of the underlying investments and capital assets which range from five to ten years. Interest is accrued monthly on any over or under recovered balances. Approved components of the GPRC 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, Energy Efficiency (EE) 2017 Program, Clean Energy Future–Energy Efficiency (CEF-EE), the Transition Renewable Energy Certificate (TRECs) Program and Clean Energy Act Studies (CEAS). •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: Pursuant to the adoption of accounting guidance for employers’ defined benefit pension and OPEB plans, PSE&G recorded the unrecognized costs for defined benefit pension and other OPEB plans on the balance sheet as a Regulatory Asset. 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 (USF); (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. •TAC: This represents the over or under collected balances associated with the return of excess accumulated deferred income taxes and the flowback of previously realized and current tax repair deductions under a mechanism approved by the BPU in PSE&G’s 2018 Distribution Base Rate Case Settlement. Over or under collected balances are returned or recovered through an annual filing. PSE&G includes a return component on the flowback of the excess accumulated deferred income taxes and the previously realized tax repairs. Interest is accrued monthly on any over or under recovered balances. •ZEC Liability: This represents amounts to be returned to customers for overcollections, including interest associated with the ZEC program whereby PSE&G purchases ZECs from eligible nuclear plants. Significant 2021 regulatory orders received and currently pending rate filings with the BPU by PSE&G are as follows: •BGS—In January 2022, the BPU approved changes to BGS rates as a result of the FERC-approved changes to transmission charges, primarily as a result of the decrease in PSE&G’s transmission formula rate ROE. PSE&G’s BGS customers will be credited over a 12-month period effective February 1, 2022. •BGSS—In March 2021, the BPU gave final approval to PSE&G’s request to maintain the current BGSS rate of 32 cents per therm which had been provisionally approved effective October 1, 2020. In June 2021, PSE&G made its annual BGSS filing with the BPU requesting to maintain the current BGSS rate of 32 cents and increase its BGSS Balancing Charge from 8.6 cents to 9.3 cents per therm which the BPU approved on a provisional basis in November 2021. Under BGSS Orders issued by the BPU, New Jersey gas distribution companies (GDCs) may self-implement up to a 5% BGSS rate increase effective December 1 of the current year, and February 1 of the following year, with one month’s advance notice to the BPU and New Jersey Rate Counsel, and implement a decrease in its BGSS rate at any time during the year upon five days’ notice to the BPU and New Jersey Rate Counsel. In November 2021, the BPU approved a waiver filed by PSE&G, along with other New Jersey GDCs, that allowed the GDCs to self-implement a BGSS increase of up to 5% effective December 1, 2021. As a result, PSE&G implemented a 5% increase resulting in a BGSS rate of 36 cents per therm, in addition to the provisionally approved increase in the BGSS Balancing Charge, both with effective dates of December 1, 2021. In December 2021, PSE&G gave notice of a second 5% self-implementing increase, effective February 1, 2022, resulting in a BGSS rate of 41 cents per therm. •CEF-Energy Cloud (EC) or Advanced Metering Infrastructure (AMI) Initiative—In January 2021, the BPU approved PSE&G’s CEF-EC filing to spend $707 million in order to provide its 2.3 million electric customers with smart meters over the next four years. All of the capital and operating costs of the program will be recovered in PSE&G’s next base rate case, expected in the second half of 2024. From the start of the program until the commencement of new base rates, the return on and of the capital portion of the program will be included for recovery in those rates, as well as operating costs and stranded costs associated with the retirement of the existing meters. •CEF-Electric Vehicles (EV)—In January 2021, the BPU approved a program for PSE&G to provide investments of approximately $166 million for EV charging infrastructure. All of the capital and operating costs of the program will be recovered in PSE&G’s next base rate case. From the start of the program until the commencement of new base rates, the return on and of the capital portion of the program will be included for recovery in those rates, as well as operating costs. •Community Solar Energy Pilot (CSEP) Program, a New Component of the GPRC—In May 2021, PSE&G made its initial filing for recovery of costs related to the CSEP program. New Jersey’s Clean Energy Act provided for the establishment of a "Community Solar Energy Pilot Program” which permits electric customers to participate in a solar energy project that is remotely located from their properties but is within their electric public utility service territory. The program allows for a credit to the customer's utility bill equal to the electricity generated attributable to the customer's participation in the solar energy project. PSE&G’s filing proposes to recover an initial revenue requirement of $0.4 million associated with the CSEP Program as a new component of PSE&G’s existing electric Green Program Recovery Charge (GPRC). This matter is pending. •CIP—In February 2022, PSE&G filed its initial electric CIP cost recovery petition seeking BPU approval to recover estimated deficient electric revenues of approximately $52 million. The filing is based on a twelve month period ending May 31, 2022, with actual results through November 2021 and forecasted amounts through May 2022. The revenue deficiency is the result of lower estimated revenues as compared to a baseline revenue calculated by utilizing approved determinants from PSE&G’s last base rate case applied to current distribution rates. Due to the savings test requirement also approved with the CIP filing, PSE&G expects to recover its $52 million request over two years. New rates are proposed to be effective June 1, 2022. This matter is pending. •COVID-19 Deferral—PSE&G continues to make quarterly filings as required by the BPU and has recorded a Regulatory Asset as of December 31, 2021 of approximately $116 million for net incremental costs, including $64 million for incremental gas bad debt expense associated with customer accounts receivable, which PSE&G expects are probable of recovery under the BPU order. In September 2021, the BPU extended the period to December 31, 2022 during which incremental costs attributable to COVID-19 could be deferred as Regulatory Assets. •Energy Strong (ES) II—In April 2021, the BPU approved PSE&G’s filing for a $13 million revenue increase under this investment program, effective May 2021. This increase represents the return on and of ES II electric investments placed in service through January 2021. In November, 2021, PSE&G filed a petition seeking BPU approval to recover the annualized increases in electric and gas revenue requirements associated with capitalized investment costs of the ES II Program through January 31, 2022. In February 2022, the petition was updated to reflect the actual investments and costs, and requests annual electric and gas revenue increases of $15 million and $1 million, respectively, with rates effective no earlier than May 1, 2022. This matter is pending. •GPRC—In June 2021, the BPU approved as final the GPRC rates approved by the BPU on a provisional basis in January 2021. In July 2021, PSE&G filed its 2021 GPRC cost recovery petition requesting BPU approval to recover a $2 million increase in each of electric and gas base rates annual revenues. This matter is pending. •Gas System Modernization Program II (GSMP II)—In May 2021, the BPU approved PSE&G’s December 2020 cost recovery petition to recover in gas base rates an annual revenue increase of approximately $21 million effective June 1, 2021. This increase represents the return on and of GSMP II investments placed in service through February 2021. In November 2021, the BPU approved PSE&G’s updated September 2021 GSMP II cost recovery petition to recover in gas base rates an annual revenue increase of approximately $28 million effective December 1, 2021. This increase represents the return on and of GSMP II investments in service through August 31, 2021. In December 2021, PSE&G filed its next semiannual GSMP II cost recovery petition seeking BPU approval to recover in gas base rates an estimated annual revenue increase of approximately $27 million effective June 1, 2022. This increase represents the return on and of GSMP II investments placed in service through February 28, 2022. This request will be updated in March 2022 for actual costs. •RAC—In July 2021, the BPU approved PSE&G’s RAC 28 filing requesting recovery of approximately $35 million in net MGP remediation expenditures incurred from August 1, 2019 through July 31, 2020. •SBC—In August 2021, the BPU approved PSE&G’s 2020 SBC filing to recover electric and gas costs incurred under its EE & RE and Social Programs. The new rates reflect no change to the overall SBC rates to customers but allowed a decrease in the EE & RE sub-component to be added to the Social Programs rate. The remaining rate increase requested by PSE&G for recovery of its Social Programs costs associated with its electric bad debt costs was deferred to the next SBC filing. As of December 31, 2021, PSE&G had approximately $139 million in deferred electric bad debt costs. In September 2021, the BPU approved the USF/Lifeline component of the SBC effective October 1, 2021, which provides for the recovery of costs provided to assist customers in paying their bills. •Solar Successor Incentive (SuSi) Program, a New Component of the GPRC—In July 2021, the BPU approved an order establishing the SuSi Program as a replacement to the bridge Transition Renewable Energy Certificates program approved in 2019. In its SuSI Order, the BPU directed the New Jersey EDCs to engage a SuSI Administrator to acquire, on behalf of the EDCs, Solar Renewable Energy Certificate-IIs (SREC-IIs), produced by eligible solar generation projects, which will be funded through a SuSI charge to electric customers collected by the EDCs. The order allows the EDCs to recover their costs associated with the SuSI program in an annual filing, subject to approval by the BPU. In December 2021, PSE&G filed for new rates of approximately $38 million for recovery of its expected share of SREC-II costs. PSE&G has requested that these costs be recovered as a new component of PSE&G’s existing electric GPRC, which is updated on an annual basis. •TAC—In August 2021, the BPU approved PSE&G’s updated 2020 TAC filing which provides for changes in the TAC electric and gas credits, which will result in an annual decrease of approximately $22 million in electric revenues and an annual increase of approximately $57 million in gas revenues. In October 2021, PSE&G made its annual 2021 TAC filing requesting BPU approval to reduce electric and gas revenues by approximately $15 million and $31 million, respectively, on an annual basis. This matter is pending. •Transmission Formula Rates—In June 2021, PSE&G filed its 2020 true-up adjustment pertaining to its transmission formula rates in effect for 2020. This filing resulted in an additional annual revenue requirement of $13 million more than the 2020 originally filed revenue. In October 2021, FERC approved a settlement agreement effective August 1, 2021 reached with the BPU Staff and the New Jersey Rate Counsel with respect to the level of PSE&G’s base transmission ROE and other formula rate matters. The settlement reduces PSE&G’s base ROE from 11.18% to 9.9% and provides that the settling parties will not seek changes to the transmission formula rate for three years. As a result of FERC’s approval of the settlement, PSE&G made the required compliance filing which was accepted by FERC in December 2021. In 2021, PSE&G had recorded a reduction of approximately $64 million in 2021 transmission revenues as a result of the settlement. In November 2021, PSE&G also filed its 2021 Annual Formula Rate Update with FERC for its 2022 transmission revenues under the revised ROE at 9.9% and with other settlement changes in formula rate matters, which will result in an approximate $150 million decrease in annual transmission revenue effective January 1, 2022. •Weather Normalization Charge (WNC)—In September 2021, the BPU provisionally approved PSE&G’s 2021-2022 WNC petition to refund a $2 million overcollection from the 2020-2021 Winter Period. The overcollection will be refunded to PSE&G gas customers during the 2021-2022 Winter Period. For the 2021-2022 Winter Period, the WNC was replaced by the CIP program. •ZEC Program—In October 2021, PSE&G filed a petition with the BPU requesting to refund a total of approximately $4 million, including interest, for overcollections resulting from the ZEC program. For the 2021 energy year, PSE&G purchased approximately $157 million in ZECs including interest, from the eligible nuclear plants selected by the BPU with the final payment made in August 2021. As a result of the collections and required ZEC payments, there were overcollected revenues, including interest of $4 million, which PSE&G now seeks to return to customers in 2022.
Public Service Electric and Gas Company |
Regulatory Assets And Liabilities [Line Items] |
Regulatory Assets and Liabilities | 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, 2021 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, |
|  |  | 2021 |  | 2020 |
|  |  | Millions |
| Regulatory Assets |  |  |  |  |
| Current |  |  |  |  |
| New Jersey Clean Energy Program |  | $ | 146 |  |  | $ | 143 |  |
| Electric Energy Costs—Basic Generation Service (BGS) |  | 67 |  |  | 60 |  |
| 2018 Distribution Base Rate Case Regulatory Assets (BRC) |  | 56 |  |  | 56 |  |
| Tax Adjustment Credit (TAC) |  | 44 |  |  | — |  |
| Conservation Incentive Program (CIP) |  | 36 |  |  | — |  |
| Formula Rate True-up |  | 13 |  |  | 23 |  |
| SBC |  | — |  |  | 82 |  |
| Other |  | 2 |  |  | 5 |  |
| Total Current Regulatory Assets |  | 364 |  |  | 369 |  |
| Noncurrent |  |  |  |  |
| Deferred Income Tax Regulatory Assets |  | $ | 1,064 |  |  | $ | 1,014 |  |
| Pension and OPEB Costs |  | 1,043 |  |  | 1,489 |  |
| Manufactured Gas Plant (MGP) Remediation Costs |  | 220 |  |  | 320 |  |
| Green Program Recovery Charges (GPRC) |  | 211 |  |  | 139 |  |
| Asset Retirement Obligation |  | 191 |  |  | 184 |  |
| Electric Transmission and Gas Cost of Removal |  | 174 |  |  | 189 |  |
| Remediation Adjustment Charge (RAC) (Other SBC) |  | 156 |  |  | 134 |  |
| SBC (Electric Bad Debt) |  | 139 |  |  | — |  |
| COVID-19 Deferral |  | 116 |  |  | 51 |  |
| Deferred Storm Costs |  | 109 |  |  | 99 |  |
| BRC |  | 47 |  |  | 103 |  |
| Other |  | 135 |  |  | 150 |  |
| Total Noncurrent Regulatory Assets |  | 3,605 |  |  | 3,872 |  |
| Total Regulatory Assets |  | $ | 3,969 |  |  | $ | 4,241 |  |
|  |  | As of December 31, |
|  |  | 2021 |  | 2020 |
|  |  | Millions |
| Regulatory Liabilities |  |  |  |  |
| Current |  |  |  |  |
| Deferred Income Tax Regulatory Liabilities |  | $ | 288 |  |  | $ | 250 |  |
| Formula Rate True-up |  | 42 |  |  | — |  |
| GPRC |  | 19 |  |  | 1 |  |
| ZEC Liability |  | 11 |  |  | 17 |  |
| Gas Costs—BGSS |  | 5 |  |  | 20 |  |
| Other |  | 23 |  |  | 6 |  |
| Total Current Regulatory Liabilities |  | 388 |  |  | 294 |  |
| Noncurrent |  |  |  |  |
| Deferred Income Tax Regulatory Liabilities |  | $ | 2,443 |  |  | $ | 2,670 |  |
| Other |  | 54 |  |  | 37 |  |
| Total Noncurrent Regulatory Liabilities |  | 2,497 |  |  | 2,707 |  |
| Total Regulatory Liabilities |  | $ | 2,885 |  |  | $ | 3,001 |  |
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: •Asset Retirement Obligation: 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 from 2010 through 2018, which are being amortized over five years pursuant to the 2018 Distribution Base Rate Case Settlement. •CIP: The CIP reduces the impact on distribution revenues from changes in sales volumes and demand for most customers. The CIP, which is calculated annually, 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 (ROE) test and ceilings on customer rate increases. The CIP became effective in June 2021 for electric revenues and October 2021 for gas revenues. The gas CIP replaced the Weather Normalization Clause. •COVID-19 Deferral: These amounts represent incremental costs related to COVID-19 as authorized for deferral in an order issued by the BPU to all New Jersey regulated utilities in July 2020. The BPU authorized such utilities to create a COVID-19-related Regulatory Asset by deferring on their books and records the prudently incurred incremental costs related to COVID-19 during the Regulatory Asset period, beginning on March 9, 2020 through September 30, 2021, or 60 days after the New Jersey governor determines that the Public Health Emergency is no longer in effect, or in the absence of such a determination, 60 days from the time the Public Health Emergency automatically terminates by law, whichever is later. Deferred costs are to be offset by any federal or state assistance that the utility may receive as a direct result of the COVID-19 pandemic. Utilities must file quarterly reports of the costs incurred and offsets. Each participating utility must file a petition documenting its prudently incurred incremental COVID-19 costs by December 31, 2021, or within 60 days of the close of the Regulatory Asset period as described above, whichever is later. In September 2021, the BPU extended the deferral period to December 31, 2022. Any potential rate recovery, including any prudency determinations and the appropriate period of recovery, will be addressed through that filing, or in the alternative, the utility may request that the BPU defer consideration of rate recovery for a future base rate case. •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 flowback to customers of accumulated deferred income taxes related to tax repair deductions. As part of its base rate case settlement with the BPU and the establishment of the TAC mechanism in 2018, 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 as realized which results in the recording of a Regulatory Asset upon flowback. For the years ended December 31, 2021, 2020 and 2019, PSE&G had provided $22 million, $31 million and $58 million, respectively, in current tax repair flowbacks to customers. The recovery and amortization of the tax repair-related Deferred Income Tax Regulatory Assets will be determined in PSE&G’s subsequent base rate cases. •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 (Tax Act), and accumulated deferred income taxes from previously realized distribution-related tax repair deductions. As part of its settlement with its regulators, PSE&G agreed to refund the excess deferred income taxes as follows: •Unprotected distribution-related excess deferred income taxes are being refunded to customers over five years through PSE&G’s TAC mechanism as approved in its 2018 distribution base rate proceeding. As of December 31, 2021, the balance remaining to be flowed back to customers was approximately $371 million with the remaining flowback period through 2024. •Protected distribution-related excess deferred income taxes are being refunded to customers over the remaining useful life of distribution property, plant and equipment through PSE&G’s TAC mechanism. As of December 31, 2021, the balance remaining to be flowed back to customers was approximately $905 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, 2021, the balance remaining to be flowed back to customers was approximately $462 million through 2028. •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, 2021, the balance remaining to be flowed back to customers was approximately $939 million. •Unprotected transmission-related deferred income taxes were fully refunded to customers in 2019 and 2020. •Deferred Storm Costs: Incremental costs incurred in the restoration and related costs from major storms in 2019, 2020 and 2021 for which PSE&G will seek recovery in its next base rate proceeding. •Electric and Gas Cost of Removal: PSE&G accrues and collects in rates for the cost of removing, dismantling and disposing of its T&D assets 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. •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. •Formula Rate True-Up: PSE&G’s transmission revenues are earned under a FERC-approved annual formula rate mechanism which provides for an annual filing of an estimated revenue requirement with rates effective January 1 of each year and a true-up to that estimate based on actual revenue requirements. •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: This amount represents costs of the over or under collected balances associated with various Energy Efficiency and Renewable Energy (EE & RE) Programs. PSE&G files annually with the BPU for recovery of amounts that include a return on and of its investment over the lives of the underlying investments and capital assets which range from five to ten years. Interest is accrued monthly on any over or under recovered balances. Approved components of the GPRC 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, Energy Efficiency (EE) 2017 Program, Clean Energy Future–Energy Efficiency (CEF-EE), the Transition Renewable Energy Certificate (TRECs) Program and Clean Energy Act Studies (CEAS). •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: Pursuant to the adoption of accounting guidance for employers’ defined benefit pension and OPEB plans, PSE&G recorded the unrecognized costs for defined benefit pension and other OPEB plans on the balance sheet as a Regulatory Asset. 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 (USF); (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. •TAC: This represents the over or under collected balances associated with the return of excess accumulated deferred income taxes and the flowback of previously realized and current tax repair deductions under a mechanism approved by the BPU in PSE&G’s 2018 Distribution Base Rate Case Settlement. Over or under collected balances are returned or recovered through an annual filing. PSE&G includes a return component on the flowback of the excess accumulated deferred income taxes and the previously realized tax repairs. Interest is accrued monthly on any over or under recovered balances. •ZEC Liability: This represents amounts to be returned to customers for overcollections, including interest associated with the ZEC program whereby PSE&G purchases ZECs from eligible nuclear plants. Significant 2021 regulatory orders received and currently pending rate filings with the BPU by PSE&G are as follows: •BGS—In January 2022, the BPU approved changes to BGS rates as a result of the FERC-approved changes to transmission charges, primarily as a result of the decrease in PSE&G’s transmission formula rate ROE. PSE&G’s BGS customers will be credited over a 12-month period effective February 1, 2022. •BGSS—In March 2021, the BPU gave final approval to PSE&G’s request to maintain the current BGSS rate of 32 cents per therm which had been provisionally approved effective October 1, 2020. In June 2021, PSE&G made its annual BGSS filing with the BPU requesting to maintain the current BGSS rate of 32 cents and increase its BGSS Balancing Charge from 8.6 cents to 9.3 cents per therm which the BPU approved on a provisional basis in November 2021. Under BGSS Orders issued by the BPU, New Jersey gas distribution companies (GDCs) may self-implement up to a 5% BGSS rate increase effective December 1 of the current year, and February 1 of the following year, with one month’s advance notice to the BPU and New Jersey Rate Counsel, and implement a decrease in its BGSS rate at any time during the year upon five days’ notice to the BPU and New Jersey Rate Counsel. In November 2021, the BPU approved a waiver filed by PSE&G, along with other New Jersey GDCs, that allowed the GDCs to self-implement a BGSS increase of up to 5% effective December 1, 2021. As a result, PSE&G implemented a 5% increase resulting in a BGSS rate of 36 cents per therm, in addition to the provisionally approved increase in the BGSS Balancing Charge, both with effective dates of December 1, 2021. In December 2021, PSE&G gave notice of a second 5% self-implementing increase, effective February 1, 2022, resulting in a BGSS rate of 41 cents per therm. •CEF-Energy Cloud (EC) or Advanced Metering Infrastructure (AMI) Initiative—In January 2021, the BPU approved PSE&G’s CEF-EC filing to spend $707 million in order to provide its 2.3 million electric customers with smart meters over the next four years. All of the capital and operating costs of the program will be recovered in PSE&G’s next base rate case, expected in the second half of 2024. From the start of the program until the commencement of new base rates, the return on and of the capital portion of the program will be included for recovery in those rates, as well as operating costs and stranded costs associated with the retirement of the existing meters. •CEF-Electric Vehicles (EV)—In January 2021, the BPU approved a program for PSE&G to provide investments of approximately $166 million for EV charging infrastructure. All of the capital and operating costs of the program will be recovered in PSE&G’s next base rate case. From the start of the program until the commencement of new base rates, the return on and of the capital portion of the program will be included for recovery in those rates, as well as operating costs. •Community Solar Energy Pilot (CSEP) Program, a New Component of the GPRC—In May 2021, PSE&G made its initial filing for recovery of costs related to the CSEP program. New Jersey’s Clean Energy Act provided for the establishment of a "Community Solar Energy Pilot Program” which permits electric customers to participate in a solar energy project that is remotely located from their properties but is within their electric public utility service territory. The program allows for a credit to the customer's utility bill equal to the electricity generated attributable to the customer's participation in the solar energy project. PSE&G’s filing proposes to recover an initial revenue requirement of $0.4 million associated with the CSEP Program as a new component of PSE&G’s existing electric Green Program Recovery Charge (GPRC). This matter is pending. •CIP—In February 2022, PSE&G filed its initial electric CIP cost recovery petition seeking BPU approval to recover estimated deficient electric revenues of approximately $52 million. The filing is based on a twelve month period ending May 31, 2022, with actual results through November 2021 and forecasted amounts through May 2022. The revenue deficiency is the result of lower estimated revenues as compared to a baseline revenue calculated by utilizing approved determinants from PSE&G’s last base rate case applied to current distribution rates. Due to the savings test requirement also approved with the CIP filing, PSE&G expects to recover its $52 million request over two years. New rates are proposed to be effective June 1, 2022. This matter is pending. •COVID-19 Deferral—PSE&G continues to make quarterly filings as required by the BPU and has recorded a Regulatory Asset as of December 31, 2021 of approximately $116 million for net incremental costs, including $64 million for incremental gas bad debt expense associated with customer accounts receivable, which PSE&G expects are probable of recovery under the BPU order. In September 2021, the BPU extended the period to December 31, 2022 during which incremental costs attributable to COVID-19 could be deferred as Regulatory Assets. •Energy Strong (ES) II—In April 2021, the BPU approved PSE&G’s filing for a $13 million revenue increase under this investment program, effective May 2021. This increase represents the return on and of ES II electric investments placed in service through January 2021. In November, 2021, PSE&G filed a petition seeking BPU approval to recover the annualized increases in electric and gas revenue requirements associated with capitalized investment costs of the ES II Program through January 31, 2022. In February 2022, the petition was updated to reflect the actual investments and costs, and requests annual electric and gas revenue increases of $15 million and $1 million, respectively, with rates effective no earlier than May 1, 2022. This matter is pending. •GPRC—In June 2021, the BPU approved as final the GPRC rates approved by the BPU on a provisional basis in January 2021. In July 2021, PSE&G filed its 2021 GPRC cost recovery petition requesting BPU approval to recover a $2 million increase in each of electric and gas base rates annual revenues. This matter is pending. •Gas System Modernization Program II (GSMP II)—In May 2021, the BPU approved PSE&G’s December 2020 cost recovery petition to recover in gas base rates an annual revenue increase of approximately $21 million effective June 1, 2021. This increase represents the return on and of GSMP II investments placed in service through February 2021. In November 2021, the BPU approved PSE&G’s updated September 2021 GSMP II cost recovery petition to recover in gas base rates an annual revenue increase of approximately $28 million effective December 1, 2021. This increase represents the return on and of GSMP II investments in service through August 31, 2021. In December 2021, PSE&G filed its next semiannual GSMP II cost recovery petition seeking BPU approval to recover in gas base rates an estimated annual revenue increase of approximately $27 million effective June 1, 2022. This increase represents the return on and of GSMP II investments placed in service through February 28, 2022. This request will be updated in March 2022 for actual costs. •RAC—In July 2021, the BPU approved PSE&G’s RAC 28 filing requesting recovery of approximately $35 million in net MGP remediation expenditures incurred from August 1, 2019 through July 31, 2020. •SBC—In August 2021, the BPU approved PSE&G’s 2020 SBC filing to recover electric and gas costs incurred under its EE & RE and Social Programs. The new rates reflect no change to the overall SBC rates to customers but allowed a decrease in the EE & RE sub-component to be added to the Social Programs rate. The remaining rate increase requested by PSE&G for recovery of its Social Programs costs associated with its electric bad debt costs was deferred to the next SBC filing. As of December 31, 2021, PSE&G had approximately $139 million in deferred electric bad debt costs. In September 2021, the BPU approved the USF/Lifeline component of the SBC effective October 1, 2021, which provides for the recovery of costs provided to assist customers in paying their bills. •Solar Successor Incentive (SuSi) Program, a New Component of the GPRC—In July 2021, the BPU approved an order establishing the SuSi Program as a replacement to the bridge Transition Renewable Energy Certificates program approved in 2019. In its SuSI Order, the BPU directed the New Jersey EDCs to engage a SuSI Administrator to acquire, on behalf of the EDCs, Solar Renewable Energy Certificate-IIs (SREC-IIs), produced by eligible solar generation projects, which will be funded through a SuSI charge to electric customers collected by the EDCs. The order allows the EDCs to recover their costs associated with the SuSI program in an annual filing, subject to approval by the BPU. In December 2021, PSE&G filed for new rates of approximately $38 million for recovery of its expected share of SREC-II costs. PSE&G has requested that these costs be recovered as a new component of PSE&G’s existing electric GPRC, which is updated on an annual basis. •TAC—In August 2021, the BPU approved PSE&G’s updated 2020 TAC filing which provides for changes in the TAC electric and gas credits, which will result in an annual decrease of approximately $22 million in electric revenues and an annual increase of approximately $57 million in gas revenues. In October 2021, PSE&G made its annual 2021 TAC filing requesting BPU approval to reduce electric and gas revenues by approximately $15 million and $31 million, respectively, on an annual basis. This matter is pending. •Transmission Formula Rates—In June 2021, PSE&G filed its 2020 true-up adjustment pertaining to its transmission formula rates in effect for 2020. This filing resulted in an additional annual revenue requirement of $13 million more than the 2020 originally filed revenue. In October 2021, FERC approved a settlement agreement effective August 1, 2021 reached with the BPU Staff and the New Jersey Rate Counsel with respect to the level of PSE&G’s base transmission ROE and other formula rate matters. The settlement reduces PSE&G’s base ROE from 11.18% to 9.9% and provides that the settling parties will not seek changes to the transmission formula rate for three years. As a result of FERC’s approval of the settlement, PSE&G made the required compliance filing which was accepted by FERC in December 2021. In 2021, PSE&G had recorded a reduction of approximately $64 million in 2021 transmission revenues as a result of the settlement. In November 2021, PSE&G also filed its 2021 Annual Formula Rate Update with FERC for its 2022 transmission revenues under the revised ROE at 9.9% and with other settlement changes in formula rate matters, which will result in an approximate $150 million decrease in annual transmission revenue effective January 1, 2022. •Weather Normalization Charge (WNC)—In September 2021, the BPU provisionally approved PSE&G’s 2021-2022 WNC petition to refund a $2 million overcollection from the 2020-2021 Winter Period. The overcollection will be refunded to PSE&G gas customers during the 2021-2022 Winter Period. For the 2021-2022 Winter Period, the WNC was replaced by the CIP program. •ZEC Program—In October 2021, PSE&G filed a petition with the BPU requesting to refund a total of approximately $4 million, including interest, for overcollections resulting from the ZEC program. For the 2021 energy year, PSE&G purchased approximately $157 million in ZECs including interest, from the eligible nuclear plants selected by the BPU with the final payment made in August 2021. As a result of the collections and required ZEC payments, there were overcollected revenues, including interest of $4 million, which PSE&G now seeks to return to customers in 2022.

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