~~Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities~~

This accounting standard’s amendments more closely align hedge accounting with the companies’ risk management activities in the financial statements. The amendments expand hedge accounting for both non-financial and financial risk components by

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~~permitting contractually specified components~~PSEG Power primarily sells to ~~designate~~the Independent System Operators (ISOs) energy and ancillary services which are separately transacted in the day-ahead or real-time energy markets. The energy and ancillary services performance obligations are typically satisfied over time as delivered and revenue is recognized accordingly. Historically, wholesale load contracts have been executed in the different ISO regions for the bundled supply of energy, capacity, renewable energy credits (RECs) and ancillary services representing PSEG Power’s performance obligations. Revenue for these contracts is recognized over time as the ~~hedged risk~~bundled service is provided to the customer. PSEG generally reports electricity sales and purchases conducted with those individual ISOs net on an hourly basis in ~~a cash flow hedge involving~~either Operating Revenues or Energy Costs in its Condensed Consolidated Statements of Operations. The classification depends on the ~~purchase or sale of non-financial assets or variable rate financial instruments. Additionally,~~net hourly activity.

PSEG Power enters into capacity sales and capacity purchases through the ~~amendments ease the operational burden of applying hedge accounting by allowing more time to prepare hedge documentation, and allow effectiveness assessments to be performed~~ISOs. The transactions are reported on a ~~qualitative~~net basis ~~after hedge inception.~~dependent on PSEG Power’s monthly net sale or purchase position through the individual ISOs. The performance obligations with the ISOs are satisfied over time upon delivery of the capacity and revenue is recognized accordingly. In addition to capacity sold through the ISOs, PSEG Power sells capacity through bilateral contracts and the related revenue is reported on a gross basis and recognized over time upon delivery of the capacity.

In December 2022, PJM called its first ISO-wide Maximum Generation Emergency Action, which triggered a Performance Assessment Interval (PAI) event. During the PAI, PSEG Power’s Salem 2 nuclear plant incurred penalties due to an unplanned outage during the second day of the event. Our remaining nuclear plants earned bonus payments during the entire event. Additional revenue has been recorded in 2023 upon clarification from the ISO on expected bonus payments and receipts to date. The new guidance is effective for annual and interim periods beginning after December 15, 2018. The standard requires using a modified retrospective method upon adoption. Early adoption is permitted. PSEG is currently analyzing theestimated impact of ~~this standard on its consolidated~~Salem 2’s penalties and bonuses earned by the other units was not material to PSEG’s financial ~~statements.~~ results in 2022 or 2023.

~~Measurement~~PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants have been awarded Zero Emission Certificates (ZECs) by the BPU through May 2025. These nuclear plants are expected to receive ZEC revenue from the electric distribution companies (EDCs) in New Jersey. PSEG Power recognizes revenue when the units generate electricity, which is when the performance obligation is satisfied. These revenues are included in PJM Sales in the following tables. See Note 3. Early Plant Retirements/Asset Dispositions and Impairments for additional information.

Gas Contracts—PSEG Power sells wholesale natural gas, primarily through an index based full-requirements Basic Gas Supply Service (BGSS) contract with PSE&G to meet the gas supply requirements of ~~Credit Losses on Financial Instruments~~

~~This accounting standard provides~~PSE&G’s customers. The BGSS contract remains in effect unless terminated by either party with a ~~new model for recognizing credit losses on financial assets carried at amortized cost.~~two-year notice. Based upon the availability of natural gas, storage and pipeline capacity beyond PSE&G’s daily needs, PSEG Power also sells gas and pipeline capacity to other counterparties under bilateral contracts. The ~~new model requires entities to use an estimate~~performance obligation is primarily the delivery of ~~expected credit losses that will be~~gas which is satisfied over time. Revenue is recognized as ~~an impairment allowance rather than~~gas is delivered or pipeline capacity is released.

PSEG LI Contract—PSEG LI has a ~~direct write-down~~contract with LIPA which generates revenues. PSEG LI’s subsidiary, Long Island Electric

Utility Servco, LLC (Servco) records costs which are recovered from LIPA and records the recovery of ~~the amortized cost basis. The estimate of expected credit losses~~those costs as revenues

when Servco is ~~to be based on past events, current conditions and supportable forecasts over~~ a reasonable period. For purchased financial assets with credit deterioration, a similar model is to be used; however, the initial allowance will be added to the purchase price rather than reported as an allowance. Credit losses on available-for-sale securities should be measured in a manner similar to current GAAP; however, this standard requires those credit losses to be presented as an allowance, rather than a write-down. This new standard also requires additional disclosures of credit quality indicators for each class of financial asset disaggregated by year of origination.

~~The standard is effective for annual and interim periods beginning after December 15, 2019; however, entities may adopt early beginning~~principal in the ~~annual or interim periods after December 15, 2018.~~ transaction.

Other Revenues from Contracts with Customers

PSEG Power has entered into long-term contracts with LIPA for energy management and fuel procurement services. Revenue is ~~currently analyzing the impact of this standard on its financial statements.~~recognized over time as services are rendered.

~~Statement of Cash Flows: Classification of Certain Cash Receipts~~Revenues Unrelated to Contracts with Customers

PSEG Power’s revenues unrelated to contracts with customers include electric, gas and ~~Cash Payments~~certain energy-related transactions accounted for in accordance with Derivatives and Hedging accounting guidance. See Note 12. Financial Risk Management Activities for further discussion.

~~This~~Energy Holdings generates lease revenues which are recorded pursuant to lease accounting ~~standard reduces the diversity in practice in how certain cash receipts and cash payments are presented and classified in the Statement of Cash Flows.~~guidance.

~~The standard is effective for annual and interim periods beginning after December~~

15 2017; however, entities may adopt early, including in an interim period. PSEG does not anticipate any current impact on PSEG’s financial statements. PSEG will adopt this standard as of January 1, 2018 using a retrospective transition method to each period presented.

~~Statement of Cash Flows: Restricted Cash~~

This accounting standard requires entities to explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents, either in a narrative or a tabular format. Amounts generally described as restricted cash or restricted cash equivalents should be included in entities’ reconciliation of beginning-of-period and end-of-period amounts in the Statement of Cash Flows.

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early, including in an interim period. PSEG plans to adopt this standard on January 1, 2018 using a retrospective transition method for each period presented. PSEG will continue the current balance sheet classification of restricted cash or restricted cash equivalents. PSEG will provide a reconciliation of cash and cash equivalents and restricted cash or restricted cash equivalents and include a description of these amounts.

~~Simplifying the Test for Goodwill Impairment~~

This accounting standard requires an entity to perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable.

An entity should apply this standard on a prospective basis and will be required to disclose the nature of and reason for the change in accounting principle upon transition. The new standard is effective for impairment tests for periods beginning January 1, 2020. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. PSEG is currently assessing the impact of this guidance upon its financial statements.

~~Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (OPEB)~~

~~This accounting standard was issued to improve the presentation of net periodic pension cost and net periodic OPEB cost.~~

Under the new guidance, entities are required to report the service cost component in the same line item or items as other compensation costs arising from services rendered by their employees during the period. The other components of net benefit

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Disaggregation of Revenues

cost are required to be presented in the Statement of Operations separately from the service cost component after Operating Income. Additionally, only the service cost component will be eligible for capitalization, when applicable.



	PSE&G		PSEG Power & Other (A)		Eliminations		Consolidated
	Millions
Three Months Ended June 30, 2023
Revenues from Contracts with Customers
Electric Distribution	$	784	$	—	$	—	$	784
Gas Distribution	274		—		—		274
Transmission	447		—		—		447
Electricity and Related Product Sales
PJM
Third-Party Sales	—		211		—		211
Sales to Affiliates	—		27		(27)		—
NYISO	—		—		—		—
ISO-NE	—		3		—		3
Gas Sales
Third-Party Sales	—		26		—		26
Sales to Affiliates	—		115		(115)		—
Other Revenues from Contracts with Customers (B)	94		153		(1)		246
Total Revenues from Contracts with Customers	1,599		535		(143)		1,991
Revenues Unrelated to Contracts with Customers (C)	63		367		—		430
Total Operating Revenues	$	1,662	$	902	$	(143)	$	2,421

The standard requires the amendments to be applied retrospectively for the presentation of the service cost component and the other cost components of net periodic pension cost and net periodic OPEB cost in the Statement of Operations and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic pension and OPEB costs.



	PSE&G		PSEG Power & Other (A)		Eliminations		Consolidated
	Millions
Six Months Ended June 30, 2023
Revenues from Contracts with Customers
Electric Distribution	$	1,514	$	—	$	—	$	1,514
Gas Distribution	1,233		—		—		1,233
Transmission	872		—		—		872
Electricity and Related Product Sales
PJM
Third-Party Sales	—		487		—		487
Sales to Affiliates	—		58		(58)		—
NYISO	—		—		—		—
ISO-NE	—		6		—		6
Gas Sales
Third-Party Sales	—		112		—		112
Sales to Affiliates	—		648		(648)		—
Other Revenues from Contracts with Customers (B)	172		306		(2)		476
Total Revenues from Contracts with Customers	3,791		1,617		(708)		4,700
Revenues Unrelated to Contracts with Customers (C)	164		1,312		—		1,476
Total Operating Revenues	$	3,955	$	2,929	$	(708)	$	6,176

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early adoption is permitted for an entity in any interim or annual period. PSEG is currently analyzing the impact of this standard on its financial statements.

~~Premium Amortization on Purchased Callable Debt Securities~~

This accounting standard was issued to shorten the amortization period for certain callable debt securities held at a premium. Specifically, the standard requires the premium to be amortized to the earliest call date. The amendments do not require an accounting change for securities held at a discount; the discount continues to be amortized to maturity.

The standard is effective for annual and interim reporting periods beginning after December 15, 2018. Early adoption is permitted for an entity in any interim or annual period. If an entity early adopts the standard in an interim period, any

adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity should apply this standard on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. Additionally, in the period of adoption, an entity should provide disclosures about a change in accounting principle. PSEG is currently analyzing the impact of this standard on its financial statements.

~~Stock Compensation - Scope of Modification Accounting~~

This accounting standard provides clarity and reduces both diversity in practice and complexity when applying the stock compensation guidance to a change in the terms or conditions of a stock-based payment award. Specifically, the standard provides guidance as to which changes to the terms or conditions of a stock-based payment award require an entity to apply modification accounting.

The standard is effective for all entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted, including adoption in any interim period, for reporting periods for which financial statements have not yet been issued. This standard should be applied prospectively to an award modified on or after the adoption date. PSEG plans to adopt this standard effective January 1, 2018.

~~Note 3. Early Plant Retirements~~

~~Fossil~~

In October 2016, Power determined that it would cease generation operations of the existing coal/gas units at the Hudson and Mercer generating stations on June 1, 2017. Both units were available to operate through May 31, 2017 and were subsequently retired from operation on June 1, 2017.

In the latter half of 2016, PSEG and Power recognized pre-tax charges in Energy Costs and Operation and Maintenance (O&M) of $62 million and $53 million, respectively, related to coal inventory adjustments, capacity penalties, materials and supplies inventory reserve adjustments for parts that cannot be used at other generating units, employee-related severance benefits costs and construction work in progress impairments, among other shut down items. In addition to these charges, Power recognized Depreciation and Amortization (D&A) during 2016 of $571 million due to the significant shortening of the expected economic useful lives of Hudson and Mercer.

As of June 1, 2017, Power recognized total D&A of $964 million for the Hudson and Mercer units to reflect the end of their economic useful lives in 2017. In the three and nine months ended September 30, 2017, Power recognized pre-tax charges in Energy Costs of $1 million and $10 million, respectively, primarily for coal inventory lower of cost or market adjustments. For the three and nine months ended September 30, 2017, Power also recognized pre-tax charges in O&M of $8 million and $12 million, respectively, of shut down costs and an increase in the Asset Retirement Obligation due to settlements and changes in cash flow estimates, partially offset by changes in employee-related severance costs. Power currently anticipates using the sites for alternative industrial activity. However, if Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger obligations under certain environmental regulations, including possible remediation. The amounts for any such environmental remediation are neither currently probable nor estimable but may be material.

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	PSE&G		PSEG Power & Other (A)		Eliminations		Consolidated
	Millions
Three Months Ended June 30, 2022
Revenues from Contracts with Customers
Electric Distribution	$	836	$	—	$	—	$	836
Gas Distribution	317		—		—		317
Transmission	396		—		—		396
Electricity and Related Product Sales
PJM
Third-Party Sales	—		475		—		475
Sales to Affiliates	—		35		(35)		—
NYISO	—		—		—		—
ISO-NE	—		3		—		3
Gas Sales
Third-Party Sales	—		77		—		77
Sales to Affiliates	—		202		(202)		—
Other Revenues from Contracts with Customers (B)	94		150		—		244
Total Revenues from Contracts with Customers	1,643		942		(237)		2,348
Revenues Unrelated to Contracts with Customers (C)	25		(297)		—		(272)
Total Operating Revenues	$	1,668	$	645	$	(237)	$	2,076



	PSE&G		PSEG Power & Other (A)		Eliminations		Consolidated
	Millions
Six Months Ended June 30, 2022
Revenues from Contracts with Customers
Electric Distribution	$	1,556	$	—	$	—	$	1,556
Gas Distribution	1,364		—		(1)		1,363
Transmission	788		—		—		788
Electricity and Related Product Sales
PJM
Third-Party Sales	—		1,057		—		1,057
Sales to Affiliates	—		91		(91)		—
NYISO	—		88		—		88
ISO-NE	—		89		—		89
Gas Sales
Third-Party Sales	—		213		—		213
Sales to Affiliates	—		728		(728)		—
Other Revenues from Contracts with Customers (B)	179		296		(1)		474
Total Revenues from Contracts with Customers	3,887		2,562		(821)		5,628
Revenues Unrelated to Contracts with Customers (C)	65		(1,304)		—		(1,239)
Total Operating Revenues	$	3,952	$	1,258	$	(821)	$	4,389

(A)Includes revenues applicable to PSEG Power, PSEG LI and Energy Holdings.

(B)Includes primarily revenues from appliance repair services and the sale of solar renewable energy credits (SRECs) at auction at PSE&G. PSEG Power & Other includes PSEG LI’s OSA with LIPA and PSEG Power’s energy management fee with LIPA.

(C)Includes primarily alternative revenues at PSE&G principally from the CIP program and derivative contracts and lease contracts at PSEG Power & Other.

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Contract Balances

PSE&G

PSE&G did not have any material contract balances (rights to consideration for services already provided or obligations to provide services in the future for consideration already received) as of June 30, 2023 and December 31, 2022. Substantially all of PSE&G’s accounts receivable and unbilled revenues result from contracts with customers that are priced at tariff rates. Allowances represented approximately 20% of accounts receivable (including unbilled revenues) as of June 30, 2023 and December 31, 2022.

Accounts Receivable—Allowance for Credit Losses

PSE&G’s accounts receivable, including unbilled revenues, is primarily comprised of utility customer receivables for the provision of electric and gas service and appliance services, and are reported on the balance sheet as gross outstanding amounts adjusted for an allowance for credit losses. The allowance for credit losses reflects PSE&G’s best estimate of losses on the account balances. The allowance is based on PSE&G’s projection of accounts receivable aging, historical experience, economic factors and other currently available evidence, including the estimated impact of the COVID-19 pandemic on the outstanding balances as of June 30, 2023. PSE&G’s electric bad debt expense is recoverable through its Societal Benefits Clause (SBC) mechanism. As of June 30, 2023, PSE&G had a deferred balance of $137 million from electric bad debts recorded as a Regulatory Asset. In addition, as of June 30, 2023, PSE&G had deferred incremental gas bad debt expense of $68 million as a Regulatory Asset for future regulatory recovery due to the impact of the coronavirus pandemic. See Note 5. Rate Filings for additional information.

The following provides a reconciliation of PSE&G’s allowance for credit losses for the three months and six months ended June 30, 2023 and 2022:




		Three Months Ended June 30, 2023
		Millions
Balance as of March 31, 2023		$	319
Utility Customer and Other Accounts
	Provision	15
	Write-offs, net of Recoveries of $6 million	(40)
Balance as of June 30, 2023		$	294

		Six Months Ended June 30, 2023
		Millions
Balance as of January 1, 2023		$	339
Utility Customer and Other Accounts
	Provision	24
	Write-offs, net of Recoveries of $13 million	(69)
Balance as of June 30, 2023		$	294

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		Three Months Ended June 30, 2022
		Millions
Balance as of March 31, 2022		$	351
Utility Customer and Other Accounts
	Provision	6
	Write-offs, net of Recoveries of $14 million	(22)
Balance as of June 30, 2022		$	335

		Six Months Ended June 30, 2022
		Millions
Balance as of January 1, 2022		$	337
Utility Customer and Other Accounts
	Provision	39
	Write-offs, net of Recoveries of $22 million	(41)
Balance as of June 30, 2022		$	335

PSEG Power & Other

PSEG Power generally collects consideration upon satisfaction of performance obligations, and therefore, PSEG Power had no material contract balances as of June 30, 2023 and December 31, ~~2016,~~2022.

PSEG Power’s accounts receivable include amounts resulting from contracts with customers and other contracts which are out of scope of accounting guidance for revenues from contracts with customers. The majority of these accounts receivable are subject to master netting agreements. As a result, accounts receivable resulting from contracts with customers and receivables unrelated to contracts with customers are netted within Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets.

PSEG Power’s accounts receivable consist mainly of revenues from energy and ancillary services sold directly to ISOs, wholesale load contracts and capacity sales which are executed in the different ISO regions, and other counterparties. In the wholesale energy markets in which PSEG Power ~~had reduced~~operates, payment for services rendered and products transferred are typically due within 30 days of delivery. As such, there is little credit risk associated with these receivables. PSEG Power did not record an allowance for credit losses for these receivables as of June 30, 2023 or December 31, 2022. PSEG Power monitors the ~~estimated useful life~~status of ~~Bridgeport Harbor Station unit 3 (BH3)~~its counterparties on an ongoing basis to assess whether there are any anticipated credit losses.

PSEG LI did not have any material contract balances as of June 30, 2023 and December 31, 2022.

Remaining Performance Obligations under Fixed Consideration Contracts

PSEG primarily records revenues as allowed by the guidance, which states that if an entity has a right to consideration from ~~2025~~a customer in an amount that corresponds directly with the value to the ~~summer~~customer of the entity’s performance completed to date, the entity may recognize revenue in the amount to which the entity has a right to invoice. PSEG has future performance obligations under contracts with fixed consideration as follows:

Capacity Revenues from the PJM Annual Base Residual and Incremental Auctions—The Base Residual Auction is generally conducted annually three years in advance of the operating period. The 2023/2024 auction was held in June 2022. In February 2023, the results of the 2024/2025 auction held in December 2022 were released. PSEG Power expects to realize the following average capacity prices resulting from the base and incremental auctions, including unit specific bilateral contracts for previously cleared capacity obligations.



Delivery Year	$ per MW-Day	MW Cleared
June 2023 to May 2024	$50	3,700
June 2024 to May 2025	$55	3,500

Capacity transactions with the PJM Regional Transmission Organization are reported on a net basis dependent on PSEG

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Power’s monthly net sale or purchase position.

Bilateral capacity contracts—Capacity obligations pursuant to contract terms through 2029 are anticipated to result in revenues totaling $27 million.

Amended OSA—PSEG LI entered into an amended OSA with LIPA effective April 2022. The OSA remains a 12-year services contract ending in 2025 with annual fixed and variable components. The fixed fee for the provision of services thereunder in 2023 is approximately $42 million and is updated each year based on the change in the Consumer Price Index.

Note 3. Early Plant Retirements/Asset Dispositions and Impairments

Nuclear

In April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs by the BPU. Pursuant to a process established by the BPU, ZECs are purchased from selected nuclear plants and recovered through a non-bypassable distribution charge in the amount of $0.004 per kilowatt-hour (KWh) used (which is equivalent to approximately $10 per megawatt hour (MWh) generated in payments to selected nuclear plants (ZEC payment)). Each nuclear plant received ZEC revenue for approximately three years, through May 2022. That first eligibility period related to the award of ZECs from the April 2019 BPU Order has concluded.

In April 2021, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs for the three-year eligibility period starting June 2022 at the same approximate $10 per MWh received during the prior ZEC period through May 2022 referenced above. As a result, each nuclear plant is receiving ZEC revenue for an additional three years starting June 2022. The terms and conditions of this April 2021 ZEC award are the same as the ZEC period through May 2022. In May 2021, the New Jersey Division of Rate Counsel filed an appeal with the New Jersey Appellate Division of the BPU’s April 2021 decision. PSEG cannot predict the outcome of this matter.

The award of ZECs attaches certain obligations, including an obligation to repay the ZECs in the event that a plant ceases operations during the period that it was ~~more likely than not it~~awarded ZECs, subject to certain exceptions specified in the ZEC legislation. PSEG Power has and will ~~retire~~continue to recognize revenue monthly as the ~~unit~~nuclear plants generate electricity and satisfy their performance obligations. Further, the ZEC payment may be adjusted by ~~this time.~~the BPU at any time to offset environmental or fuel diversity payments that a selected nuclear plant may receive from another source.

In August 2022, the Inflation Reduction Act (IRA) was signed into law expanding incentives promoting carbon-free generation. The enacted legislation established the Production Tax Credit (PTC) for electricity generation using nuclear energy set to begin in 2024 through 2032. The expected PTC rate is up to $15/MWh subject to adjustment based upon a facility’s gross receipts. The PTC rate and the gross receipts cap are subject to annual inflation adjustments. PSEG Power is continuing to analyze the impact of the IRA on its nuclear units, including additional future guidance from the U.S. Treasury and the impact of PTCs on expected ZEC payments.

PSEG ~~and~~ Power ~~continue~~may take all necessary steps to monitor their other coal assets, including the Keystone and Conemaugh generating stations, to assess their economic viability through the end of their designated useful lives and their continued classification as held for use. The precise timing of a change in useful lives may be dependent upon events out of PSEG’s and Power’s control and may impact their abilitycease to operate ~~or maintain certain assets~~all of these plants and will incur associated costs and accounting charges in the event that the financial condition of the plants is materially adversely impacted in the future. ~~These generating stations~~This decision may be ~~impacted by factors such as environmental legislation, co-owner capital requirements~~based upon market conditions, including energy and ~~continued depressed wholesale power prices~~capacity revenues, insufficient government financial support, or, ~~capacity factors, among other things. Any early retirement or change~~ in the ~~held for use classification~~case of ~~our remaining coal units may have a material adverse impact on PSEG’s and Power’s future financial results.~~

~~Nuclear~~

~~Since 2013, several~~the Salem nuclear ~~generating stations in the United States have closed or announced early retirement due to economic reasons, or have announced being at risk for early retirement. This situation is generally due to thedecline in market prices of energy, resulting from low natural gas prices driven~~plants, decisions by the ~~growth~~Environmental Protection Agency and state environmental regulators regarding the implementation of shale gas production since 2007, the continuing cost of regulatory compliance and enhanced security for nuclear facilities and both federal and state-level policies that provide financial incentives to renewable energy such as wind and solar, but generally do not apply to nuclear generating stations. These trends have significantly reduced the revenues of nuclear generating stations while limiting their ability to reduce the unit cost of production. This may result in the electric generation industry experiencing a shift from nuclear generation to natural gas-fired generation, creating less diversitySection 316(b) of the ~~generation fleet.~~

~~If the market trends noted above continue~~Clean Water Act (CWA) and related state regulations, or ~~worsen, Power’s New Jersey nuclear generating units could cease being economically competitive which may cause Power to retire such units prior to the end of their useful lives.~~other factors. The associated costs ~~associated with any such potential retirement, which~~and accounting charges may include, among other things, ~~accelerated D&A or~~one-time impairment charges or accelerated Depreciation and Amortization Expense on the remaining carrying value of the plants, potential penalties associated with the early termination of capacity obligations and fuel contracts, accelerated asset retirement costs, severance costs, environmental remediation costs and, in certain circumstances potential additional funding of the ~~NDT~~Nuclear Decommissioning Trust Fund, which would ~~likely have~~result in a material adverse impact on PSEG’s and Power’s future financial results and cash flows. PSEG and Power continue to advocate for sound policies that recognize nuclear power as a source of reliable clean energy, free of air emissions and an important part of a diverse and reliable energy portfolio.

The following table provides the balance sheet amounts by generating station as of September 30, 2017 for significant assets and liabilities associated with Power’s owned share of its nuclear assets.

As of September 30, 2017
Hope Creek Salem Support Facilities and Other (A) Peach Bottom
Millions
Assets
Materials and Supplies Inventory $ 85
$ 81
$ —
$ 41

Nuclear Production, net of Accumulated Depreciation 452
557
204
753

Nuclear Fuel In-Service, net of Accumulated Depreciation 120
94
—
109

Construction Work in Progress (including nuclear fuel) 216
130
9
92

        Total Assets $ 873
$ 862
$ 213
$ 995

Liability
Asset Retirement Obligation $ 148
$ 162
$ —
$ 164

        Total Liabilities $ 148
$ 162
$ —
$ 164

         Net Assets $ 725
$ 700
$ 213
$ 831

NRC License Renewal Term 2046 2036/2040
—
2033/2034

% Owned 100 % 57 % —
50 %


~~(A)~~	~~Includes Hope Creek’s and Salem’s shared support facilities and other nuclear development capital.~~

~~The precise timing of any potential early retirement and resulting financial statement impact may be affected by a number of factors, including co-owner considerations, the~~ results of ~~any transmission system reliability study assessments~~operations.

Non-Nuclear

In May 2023, PSEG sold its 25% equity interest in Ocean Wind JV HoldCo, LLC. The sale proceeds approximated PSEG’s carrying value of the investment; therefore, no material gain or loss was recognized upon disposition.

In May 2023, PSEG Power entered into an agreement to sell its 50% ownership interest in Kalaeloa. The sale of PSEG Power’s limited and general partnership ownership interests closed in May and July 2023, respectively. The sale proceeds approximated PSEG Power's carrying value of the investment; therefore, no material gain or loss was recognized upon disposition.

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In March 2023, Energy Holdings completed the sale of one of its domestic energy generating facilities and recorded an immaterial pre-tax gain.

~~decommissioning trust fund requirements~~In February 2022, PSEG completed the sale of its fossil generating portfolio. As defined in each agreement, adjustments were required as a result of purchase price and ~~other commitments, as well as future energy prices.~~working capital adjustments, including an adjustment for positive or negative cash flow of the fossil generating assets based on actual performance starting after December 31, 2021 through the respective closing dates. As a result, in 2022 PSEG Power ~~maintains~~recorded a ~~NDT Fund that funds its decommissioning obligations. See Note 7. Available-for-Sale Securities.~~pre-tax impairment of approximately $43 million.

PSEG Power has retained ownership of certain assets and liabilities excluded from the transactions primarily related to obligations under certain environmental regulations, including possible remediation obligations under the New Jersey Industrial Site Recovery Act (ISRA) and the Connecticut Transfer Act (CTA). The amounts for any such environmental remediation are not currently estimable, but will likely be material.

Note 4. Variable Interest Entity (VIE)

VIE for which PSEG LI is the Primary Beneficiary

PSEG LI consolidates ~~Long Island Electric Utility~~ Servco, ~~LLC (Servco),~~ a marginally capitalized VIE, which was created for the purpose of operating LIPA’s T&D system in Long Island, New York as well as providing administrative support functions to LIPA. PSEG LI is the primary beneficiary of Servco because it directs the operations of Servco, the activity that most significantly impacts Servco’s economic performance and it has the obligation to absorb losses of Servco that could potentially be significant to Servco. Such losses would be immaterial to PSEG.

Pursuant to the OSA, Servco’s operating costs are ~~reimbursable~~paid entirely by LIPA, and therefore, PSEG LI’s risk is limited related to the activities of Servco. PSEG LI has no current obligation to provide direct financial support to Servco. In addition to ~~reimbursement~~payment of Servco’s operating costs as provided for in the OSA, PSEG LI receives an annual contract management fee. PSEG LI’s annual contractual management fee, in certain situations, could be partially offset by Servco’s annual storm costs not approved by the Federal Emergency Management Agency, limited contingent liabilities and penalties for failing to meet certain performance metrics.

For transactions in which Servco acts as principal and controls the services provided to LIPA, such as transactions with its employees for labor and labor-related activities, including pension and OPEB-related transactions, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and ~~O&M~~Operation and Maintenance (O&M) Expense, respectively. Servco recorded ~~$114~~$129 million for each of the three months ended June 30, 2023 and 2022 and $257 million and ~~$116~~$252 million for the ~~three months and $338 million and $315 million for the nine~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016,~~2022, respectively, of O&M costs, the full reimbursement of which was reflected in Operating Revenues. For transactions in which Servco acts as an agent for LIPA, it records revenues and the related expenses on a net basis, resulting in no impact on PSEG’s Condensed Consolidated Statement of Operations.

Note 5. Rate Filings

This Note should be read in conjunction with Note 6.7. Regulatory Assets and Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2022.

In addition to items previously reported in the Annual Report on Form 10-K, significant regulatory orders received and currently pending rate filings with ~~FERC and~~ the BPU ~~by PSE&G~~or FERC are as follows:

~~Transmission Formula Rate Filings~~—BGSS—In January and February 2023, PSE&G filed with the BPU two self-implementing BGSS rate reductions of 15 cents and 3 cents per therm, effective February 1, 2023 and March 1, 2023, respectively. These reductions resulted in a new BGSS rate of approximately 47 cents per therm effective March 1, 2023. In April 2023, the BPU gave final approval to PSE&G’s BGSS rate of 47 cents per therm.

In June ~~2017,~~2023, PSE&G made its annual BGSS filing with the BPU requesting a decrease to its BGSS rate to approximately 40 cents per therm, effective October 1, 2023. This matter is pending.

CIP—In February 2023, the BPU gave final approval for PSE&G to recover approximately $52 million of deficient electric revenues that resulted from the 12-month period ended May 31, 2022, with approximately $18 million approved for recovery for the first year starting on the effective date of June 15, 2022 and the remaining $34 million to be recovered starting in June 2023.

In April 2023, the BPU gave final approval for PSE&G to recover approximately $53 million of deficient gas revenues that resulted from the 12-month period ended September 30, 2022, over one year effective October 1, 2022.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

In May 2023, the BPU provisionally approved PSE&G's updated annual electric CIP petition to recover approximately $72 million of deficient electric revenues over two years that resulted from the 12-month period ended May 31, 2023, with new rates effective June 1, 2023.

In June 2023, PSE&G filed a gas CIP recovery petition seeking BPU approval to recover estimated deficient gas revenues of approximately $99 million for the 12-month period ending September 30, 2023, and an additional $11 million carryover underrecovery from the prior CIP period for a total request of $110 million. The revenue deficiency is the result of lower actual and estimated revenues as compared to a baseline established in PSE&G’s most recent distribution base rate proceeding. New rates are proposed to be effective October 1, 2023 and PSE&G expects to recover its deficiency over a one year period. This matter is pending.

COVID-19 Deferral—In May and June 2023, the BPU issued two Orders to all public utilities in New Jersey that stipulated a filing deadline for recovery of COVID-19 Regulatory Asset balances, and set forth certain filing requirements primarily related to recovery proposals to be included by each utility in their COVID-19 filings.

In July 2023, PSE&G filed a petition with the BPU in compliance with those Orders requesting recovery of its incremental costs associated with the COVID-19 pandemic. This matter is pending.

As of June 30, 2023, 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. PSE&G expects its COVID-19 Regulatory Asset balance is probable of recovery under the BPU orders.

Energy Strong II—In April 2023, the BPU approved PSE&G’s updated filing for annual electric and gas revenue increases of $16 million and $4 million, respectively, effective May 1, 2023. These increases represent the return on and of Energy Strong II investments placed in service through January 2023.

In May 2023, PSE&G filed a petition seeking BPU approval to recover an annualized increase in electric revenue requirement of approximately $15 million associated with capitalized electric investment costs of the Energy Strong II program. This increase represents the return on and of actual and forecasted investments through July 31, 2023. This matter is pending.

Gas System Modernization Program II (GSMP II)—In May 2023, the BPU approved PSE&G’s updated GSMP II cost recovery filing to recover an annual gas revenue increase of approximately $11 million effective June 1, 2023. This increase represents the return on and of GSMP II investments placed in service through February 2023.

Green Program Recovery Charges (GPRC)—In May 2023, the BPU approved PSE&G’s 2022 updated GPRC filing for annual electric and gas revenue increases of $87 million and $5 million, respectively, with new rates effective June 1, 2023.

Additionally in May 2023, the BPU approved PSE&G’s petition to increase its Clean Energy Future-EE sub program investment (a component of GPRC) by $280 million and approved a nine-month extension to make investments.

In June 2023, PSE&G filed its ~~2016~~2023 GPRC cost recovery petition requesting BPU approval for recovery of increases of $38 million and $20 million in annual electric and gas revenues, respectively. This matter is pending.

Pension—In February 2023, the BPU approved an accounting order authorizing PSE&G to modify its method for calculating the amortization of the net actuarial gain or loss component of pension expense for ratemaking purposes. This methodology change for ratemaking purposes is effective for the calendar year ending December 31, 2023 and forward. As of June 30, 2023, PSE&G has deferred $30 million as a Regulatory Asset under this methodology.

Remediation Adjustment Charge (RAC)—In January 2023, PSE&G filed its RAC 30 petition with the BPU seeking recovery of approximately $44 million of net Manufactured Gas Plant (MGP) expenditures incurred from August 1, 2021 through July 31, 2022. This matter is pending.

SBC—In January 2023, PSE&G filed a petition to increase its annual electric and gas rates by approximately $52 million and $32 million, respectively, in order to recover electric and gas costs incurred or expected to be incurred through February 2024 under its EE and Renewable Energy and Social Programs. The increase to electric rates includes the impact of increased bad debt expense as a result of the negative economic impact of the coronavirus pandemic and the resulting impact of moratoriums on collections. This matter is pending.

Tax Adjustment Credit (TAC)—In July 2023, the BPU approved PSE&G’s updated 2022 TAC filing to increase annual electric revenues by approximately $17 million and decrease annual gas revenues by approximately $42 million, with new rates effective August 1, 2023.

Transmission Formula Rates—In June 2023, PSE&G filed with FERC its 2022 true-up adjustment pertaining to its transmission formula rates in effect for ~~2016. This~~calendar year 2022, as established by its 2022 annual forecast filing. The June 2023 true-up filing resulted in ~~an adjustment~~a decrease in the 2022 annual revenue requirement of ~~$12~~approximately $21 million ~~more~~less than the ~~2016 originally filed revenues.~~revenue

~~In October 2017, the 2018 Annual Formula Rate update was filed with FERC and requests approximately $212 million in increased annual transmission revenue effective January 1, 2018, subject to true-up.~~

~~Gas System Modernization Program (GSMP)—In July of each year, PSE&G files with the BPU for base rate recovery of GSMP investments which include a return of and on its investment.~~

In October 2017, PSE&G submitted the planned update to its annual GSMP cost recovery petition, originally filed in July 2017, to include GSMP investments in service as of September 30, 2017. This filing seeks BPU approval to recover in gas base rates an annual revenue increase of $25 million effective January 1, 2018. This increase represents the return of and on investment for GSMP investments in service through September 30, 2017. This proceeding is ongoing.

~~Energy Strong Recovery Filing—In March and September of each year, PSE&G files with the BPU for base rate recovery of Energy Strong investments which include a return of and on its investment.~~

In June 2017, PSE&G submitted the planned update to its March Energy Strong cost recovery petition, originally filed in March 2017, to include Energy Strong investments in service as of May 31, 2017. This filing requested estimated annual increases in electric and gas revenues of $16 million and $2 million, respectively. In August 2017, the BPU approved these rate increases effective September 1, 2017.

In September 2017, PSE&G filed its Energy Strong electric cost recovery petition seeking BPU approval to recover the revenue requirements associated with Energy Strong capitalized investment costs placed in service from June 1, 2017 through November 30, 2017. The petition requests rates to be effective March 1, 2018, consistent with the BPU Order of approval of the

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

~~Energy Strong program. The annualized requested increase~~requirement numbers contained in ~~electric~~the forecast filing. PSE&G had previously recognized the majority of the lower revenue requirement ~~is approximately $9 million. This proceeding is ongoing.~~ in its 2022 Consolidated Statement of Operations.

~~Basic Gas Supply Services (BGSS)~~—ZEC Program—In June 2017, PSE&G made its annual BGSS filing with the BPU requesting an increase in the BGSS rate from approximately 34 cents to 37 cents per therm effective October 1, 2017. In September 2017, the BPU approved a Stipulation in this matter on a provisional basis and the BGSS rate was increased.

~~Weather Normalization Clause—In April 2017, the BPU gave final approval to PSE&G’s petition to collect $54 million in net deficiency gas revenues as a result of the warmer than normal 2015-2016 Winter Period.~~

In June 2017, PSE&G filed a petition requesting approval to collect $55 million in total net deficiency revenues comprised of $31 million in net deficiency gas revenues as a result of the warmer than normal 2016-2017 Winter Period and the remaining carryover balance of $24 million in net deficiency gas revenue from the 2015-2016 Winter Period. The deficiency gas revenue would be collected from customers over the 2017-2018 and 2018-2019 Winter Periods (October 1 through May 31). In September 2017, the BPU approved this petition on a provisional basis with rates effective October 1, 2017, allowing recovery during the 2017-2018 Winter Period.

~~Green Program Recovery Charges (GPRC)—In August 2017,~~January 2023, the BPU approved PSE&G’s petition ~~for an Energy Efficiency 2017 Program (EE 2017)~~ to extend three existing energy efficiency subprograms (multi-family, direct install and hospital efficiency) and establish two new residential energy efficiency offerings. The two new offerings include deployment of smart thermostats and a pilot program to provide residential customers with energy usage information enabling them to reduce consumption. The Order allows PSE&G to extendset the subprogram offerings and establish the residential energy efficiency sub-programs under its existing energy efficiency clause recovery process. The EE 2017 allows for $69 million of additional investment and $16 million of additional administrative and information technology costs. The EE 2017 was added as the 11thZEC refund component of the ~~GPRC~~tariff rate to zero effective ~~September~~February 1, ~~2017.~~

~~Each year PSE&G files with the BPU for annual recovery~~2023 as overcollections for the ~~11 combined~~ZEC Energy Year ended May 31, 2022 totaling $1.3 million, including interest, were refunded to customers in 2022 through January 2023.

Note 6. Leases

PSEG and its subsidiaries are both a lessor and a lessee in operating leases. As of June 30, 2023, PSEG and its subsidiaries were lessors for leases classified as operating leases or leveraged leases. See Note 7. Financing Receivables. There was no significant change in amounts reported in Note 8. Leases in the Annual Report on Form 10-K for the year ended December 31, 2022 for operating leases in which PSEG and its subsidiaries are lessees.

PSEG and its subsidiaries, as lessors, have lease agreements with lease and non-lease components, which are primarily related to generating facilities and real estate assets. Rental income from these leases is included in Operating Revenues.

A wholly owned subsidiary of ~~its electric~~PSEG Power is the lessor in an operating lease for certain parcels of land with terms through 2050, plus five optional renewal periods of ten years.

Energy Holdings is the lessor in leveraged leases. See Note 7. Financing Receivables.

Energy Holdings is the lessor in an operating lease for a domestic energy generation facility with remaining terms through 2036, and ~~gas Green Program investments which include~~in real estate assets with remaining terms through 2049. As of June 30, 2023, Energy Holdings’ property subject to these leases had a ~~return on its investment and recovery~~total carrying value of ~~expenses.~~$30 million.

In March ~~2017,~~2023, Energy Holdings completed the ~~BPU gave final approval to PSE&G’s 2016 GPRC cost recovery petition to recover approximately $37 million~~sale of one of its domestic energy generating facilities and ~~$13 million in electric and gas revenues, respectively, on~~recorded an ~~annual basis associated with PSE&G’s implementation of these BPU approved GPRC programs~~immaterial pre-tax gain.

The following is the operating lease income for the ~~period October 1, 2016 through September~~three months and six months ended June 30, ~~2017. The rates were effective May 1, 2017. This Order also included the return of approximately $5 million in remaining overcollections from the completed Securitization Transition Charge.~~ 2023 and 2022:

In June 2017, PSE&G filed its 2017 GPRC cost recovery petition requesting recovery of approximately $47 million and $13 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G's implementation of these BPU-approved programs for the period October 1, 2017 through September 30, 2018. This proceeding is ongoing.



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2023		2022		2023		2022
					Millions
Fixed Lease Income	$	6	$	8	$	12	$	16
Total Operating Lease Income	$	6	$	8	$	12	$	16

~~Remediation Adjustment Charge (RAC)~~—In June 2017, the BPU approved PSE&G's filing with respect to its RAC 24 petition allowing recovery of $41 million effective July 10, 2017 related to net Manufactured Gas Plant expenditures from August 1, 2015 through July 31, 2016.

Note 6.7. Financing Receivables

PSE&G

PSE~~&G sponsors a solar loan program~~&G’s Solar Loan Programs are designed to help finance the installation of solar power systems throughout its electric service area. Interest income on the loans is recorded on an accrual basis. The loans are ~~generally~~ paid back with ~~solar renewable energy certificates~~SRECs generated from the related installed solar electric system. PSE&G uses collection experience as a credit quality indicator for its Solar Loan Programs and conducts a comprehensive credit review for all prospective borrowers. As of June 30, 2023, none of the solar loans were impaired; however, in the event of a loan default, the basis of the solar loan would be recovered through a regulatory recovery mechanism. Therefore, no current credit losses have been recorded for Solar Loan Programs I, II and III. A substantial portion of these loan amounts are noncurrent and reported in Long-Term Investments on PSEG’s and PSE&G’s Condensed Consolidated Balance Sheets. The following table reflects the outstanding loans by class of customer, none of which ~~are~~would be considered “non-performing.”

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents



	As of
Outstanding Loans by Class of Customer	June 30, 2023		December 31, 2022
	Millions
Commercial/Industrial	$	74	$	85
Residential	3		4
Total	77		89
Current Portion (included in Accounts Receivable)	(26)		(27)
Noncurrent Portion (included in Long-Term Investments)	$	51	$	62

The solar loans originated under three Solar Loan Programs are comprised as follows:

Outstanding Loans by Class of Customer
As of As of
Consumer Loans September 30,
2017 December 31,
2016
Millions
Commercial/Industrial $ 160
$ 164

Residential 10
11

Total $ 170
$ 175

Programs

Balance as of June 30, 2023

Funding Provided

Residential Loan Term

Non-Residential Loan Term

Millions

Solar Loan I

prior to 2013

10 years

15 years

Solar Loan II

prior to 2015

10 years

15 years

Solar Loan III

largely funded as of June 30, 2023

10 years

Total

The average life of loans paid in full is eight years, which is lower than the loan terms of 10 to 15 years due to the generation of SRECs being greater than expected and/or cash payments made to the loan. Payments on all outstanding loans were current as of June 30, 2023 and have an average remaining life of approximately three years. There are no remaining residential loans outstanding under the Solar Loan I program.

Energy Holdings

Energy Holdings, through ~~several of~~ its indirect ~~subsidiary companies,~~subsidiaries, has investments in ~~domestic energy and real estate~~ assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third-party debt investor. The debt is recourse only to the assets subject to lease and is not included on PSEG’s Condensed Consolidated Balance Sheets. As an equity investor, Energy Holdings’ equity investments in the leases are comprised of the total expected lease receivables over the lease terms, ~~plus the estimated residual values at the end of the lease terms,~~ reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG’s Condensed Consolidated Balance Sheets. The more rapid depreciation of the leased property for tax purposes creates tax cash flow that will be repaid to the taxing authority in later periods. As such, the liability for such taxes due is recorded in Deferred Income Taxes on PSEG’s Condensed Consolidated Balance Sheets.

~~During the third quarter of 2016, Energy Holdings completed its annual review of estimated residual values embedded in the~~

NRG REMA, LLC (REMA) leveraged leases. The outcome indicated that the revised residual value estimates were lower than the recorded residual values and the decline was deemed to be other than temporary due to the adverse economic conditions experienced by coal generation in PJM, as discussed in Note 3. Early Plant Retirements, negatively impacting the economic outlook of the leased assets. As a result, a pre-tax write-down of $137 million was reflected in Operating Revenues in the quarter ended September 30, 2016, calculated by comparing the gross investment in theLeveraged leases before and after the revised residual estimates. During the fourth quarter of 2016, Energy Holdings recorded a $10 million pre-tax charge for its best estimate of loss related to the leveraged lease receivables as a result of the current liquidity issues facing REMA, which was reflected in Operating Revenues and is included in Gross Investments in Leasesoutstanding as of ~~December 31, 2016.~~

During the first quarter of 2017, due to continuing liquidity issues facing REMA, economic challenges facing coal generation in PJM, and based upon an ongoing review of available alternatives as well as certain recent discussions with REMA management, Energy Holdings recorded an additional $55 million pre-tax charge for its current best estimate of loss related to the lease receivables, which was reflected in Operating Revenues and is included in Gross Investments in Leases as of September 30, 2017.

In June 2017, GenOn Energy, Inc. (GenOn) and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. GenOn is a subsidiary of NRG Energy, Inc. and is the parent of REMA. REMA was not included in the GenOn filing. Energy Holdings continues to monitor the restructuring of GenOn and its possible impacts on REMA and continues to discuss the situation with GenOn. During the second quarter of 2017, Energy Holdings completed its review of estimated residual values embedded in its leveraged lease portfolio of generating assets and the outcome indicated that one of the residual value estimates was lower than the recorded residual value due to a further deterioration of market conditions and changes to operating cost estimates. This decline was determined to be other than temporary. As a result, a pre-tax write-down of $7 million was recorded in the quarter ended June 30, 2017. In addition, based on an ongoing review of (i) the liquidity challenges facing REMA and (ii) available alternatives, Energy Holdings recorded an additional $15 million pre-tax charge for its current best estimate of loss related2023 commenced in or prior to ~~lease receivables. The second quarter 2017 pre-tax write-down and additional charge were reflected in Operating Revenues and are included in Gross Investment in Leases for September 30, 2017.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

2000. The following table shows Energy Holdings’ gross and net lease ~~investment~~investments as of ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016, respectively.~~2022.



	As of
	June 30, 2023		December 31, 2022
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	223	$	249
Unearned and Deferred Income	(68)		(74)
Gross Investments in Leases	155		175
Deferred Tax Liabilities	(35)		(39)
Net Investments in Leases	$	120	$	136

As of As of
September 30,
2017 December 31,
2016
Millions
Lease Receivables (net of Non-Recourse Debt) $ 546
$ 629

Estimated Residual Value of Leased Assets 326
346

Total Investment in Rental Receivables 872
975

Unearned and Deferred Income (309 ) (326 )
Gross Investment in Leases 563
649

Deferred Tax Liabilities (631 ) (674 )
Net Investment in Leases $ (68 ) $ (25 )

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

The corresponding receivables associated with the lease portfolio are reflected ~~in the following table,~~as follows, net of non-recourse debt. The ratings in the table represent the ratings of the entities providing payment assurance to Energy Holdings.

Lease Receivables, Net of
Non-Recourse Debt

Counterparties’ Credit Rating Standard & Poor’s (S&P) as of September 30, 2017
As of September 30, 2017
Millions
AA $ 15

BBB+ — BBB- 316

BB- 133

CCC- 82

Total $ 546

~~The “BB-” and the “CCC-” ratings in the preceding table represent lease receivables related to coal and gas-fired assets in Illinois and Pennsylvania, respectively. As of~~ ~~September 30, 2017, the gross investment in the leases of such assets, net of non-recourse debt, was~~ ~~$337 million~~ (~~$(184) million, net of deferred taxes). A more detailed description of such assets under lease, as of September 30, 2017, is presented in the following table.~~

Asset Location
Gross
Investment

%
Owned
Total MW
Fuel
Type

Counterparties’
S&P Credit
Ratings
Counterparty
Millions
Powerton Station Units 5 and 6 IL $ 133
64 % 1,538
Coal BB- NRG Energy, Inc.
Joliet Station Units 7 and 8 IL $ 84
64 % 1,036
Gas BB- NRG Energy, Inc.
Keystone Station Units 1 and 2 PA $ 20
17 % 1,711
Coal CCC- REMA (A)
Conemaugh Station Units 1 and 2 PA $ 20
17 % 1,711
Coal CCC- REMA (A)
Shawville Station Units 1, 2, 3 and 4 PA $ 80
100 % 596
Gas CCC- REMA (A)

~~(A)~~

~~REMA’s parent company, GenOn, and certain~~

Lease Receivables, Net of ~~its subsidiaries (which did not include REMA) filed voluntary petitions for relief under Chapter 11~~
Non-Recourse Debt

Counterparties' Standard & Poor's (S&P) Credit Rating as of ~~the U.S. Bankruptcy Code. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time~~June 30, 2023

As of June 30, 2023

Millions

A-

BBB+ to ~~complete.~~BBB

173

Total

223

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

~~The~~PSEG recorded no credit ~~exposure~~losses for ~~lessors is partially mitigated through various credit enhancement mechanisms within~~ the ~~lease structures. These credit enhancement features vary from lease to lease and may include letters of credit or affiliate guarantees.~~leveraged leases existing on June 30, 2023. Upon the occurrence of certain defaults, indirect ~~subsidiary companies~~subsidiaries of Energy Holdings would exercise their rights and seek recovery of their ~~investment,~~investments, potentially including stepping into the lease directly to protect their investments. While these actions could ultimately protect or mitigate the loss of value, they could require the use of significant capital and trigger certain material tax obligations which could, for certain leases, wholly or partially be mitigated by tax indemnification claims against the counterparty. A bankruptcy of a lessee would likely delay and potentially limit any efforts on the part of the lessors to assert their rights upon default and could delay the monetization of claims. Failure to recover adequate value could ultimately lead to a foreclosure on the assets under lease by the lenders. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s restructuring process or the possible related impact on REMA. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments and continues to discuss the situation with GenOn. If lease rejections or foreclosures were to occur, Energy Holdings could potentially record additional pre-tax write-offs up to its gross investment in these facilities and may also be required to accelerate and pay material deferred tax liabilities to the Internal Revenue Service (IRS).

Additional factors that may impact future lease cash flows include, but are not limited to, new environmental legislation and regulation regarding air quality, water and other discharges in the process of generating electricity, market prices for fuel, electricity and capacity, overall financial condition of lease counterparties and their affiliates and the quality and condition of assets under lease.

Note ~~7. Available-for-Sale Securities~~8. Trust Investments

~~NDT~~Nuclear Decommissioning Trust (NDT) Fund

PSEG Power maintains an external master NDT to fund its share of decommissioning costs for its five nuclear facilities upon their respective termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. The funds are managed by third-party investment managers who operate under investment guidelines developed by PSEG Power.

~~Power classifies investments in the NDT Fund as available-for-sale.~~ The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund.



	As of June 30, 2023
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	Millions
Equity Securities
Domestic	$	458	$	300	$	(5)	$	753
International	361		94		(19)		436
Total Equity Securities	819		394		(24)		1,189
Available-for-Sale Debt Securities
Government	742		1		(82)		661
Corporate	585		1		(55)		531
Total Available-for-Sale Debt Securities	1,327		2		(137)		1,192
Total NDT Fund Investments (A)	$	2,146	$	396	$	(161)	$	2,381

(A)The NDT Fund Investments table excludes cash and foreign currency of $2 million as of June 30, 2023, which is part of the NDT Fund.

As of September 30, 2017
Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value

Millions
Equity Securities $ 706
$ 331
$ (5 ) $ 1,032

Debt Securities
Government 561
10
(4 ) 567

Corporate 352
7
(1 ) 358

Total Debt Securities 913
17
(5 ) 925

Other Securities 55
—
—
55

Total NDT Available-for-Sale Securities $ 1,674
$ 348
$ (10 ) $ 2,012

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents



	As of December 31, 2022
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	Millions
Equity Securities
Domestic	$	476	$	232	$	(12)	$	696
International	336		68		(28)		376
Total Equity Securities	812		300		(40)		1,072
Available-for-Sale Debt Securities
Government	721		—		(94)		627
Corporate	597		1		(69)		529
Total Available-for-Sale Debt Securities	1,318		1		(163)		1,156
Total NDT Fund Investments (A)	$	2,130	$	301	$	(203)	$	2,228

(A)The NDT Fund Investments table excludes cash and foreign currency of $2 million as of December 31, 2022, which is part of the NDT Fund.

As of December 31, 2016
Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value

Millions
Equity Securities $ 705
$ 263
$ (11 ) $ 957

Debt Securities
Government 518
8
(6 ) 520

Corporate 337
4
(4 ) 337

Total Debt Securities 855
12
(10 ) 857

Other Securities 44
—
—
44

Total NDT Available-for-Sale Securities (A) $ 1,604
$ 275
$ (21 ) $ 1,858

Net unrealized gains (losses) on debt securities of $(80) million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s Condensed Consolidated Balance Sheet as of June 30, 2023. The portion of net unrealized gains (losses) recognized in the second quarter and first six months of 2023 related to equity securities still held as of June 30, 2023 was $59 million and $114 million, respectively.


~~(A)~~	~~The NDT available-for-sale securities table excludes cash of $1 million which is part of the NDT Fund.~~

The amounts in the preceding tables do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets as shown in the following table.



	As of		As of
	June 30, 2023		December 31, 2022
	Millions
Accounts Receivable	$	32	$	14
Accounts Payable	$	23	$	6

As of As of
September 30,
2017 December 31,
2016
Millions
Accounts Receivable $ 11
$ 8

Accounts Payable $ 5
$ 5

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

The following table shows the value of securities in the NDT Fund that have been in an unrealized loss position for less than and greater than 12 months.



	As of June 30, 2023								As of December 31, 2022
	Less Than 12 Months				Greater Than 12 Months				Less Than 12 Months				Greater Than 12 Months
	Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses
	Millions
Equity Securities (A)
Domestic	$	29	$	(3)	$	8	$	(2)	$	90	$	(10)	$	9	$	(2)
International	39		(4)		41		(15)		88		(12)		38		(16)
Total Equity Securities	68		(7)		49		(17)		178		(22)		47		(18)
Available-for-Sale Debt Securities
Government (B)	206		(6)		406		(76)		301		(27)		292		(67)
Corporate (C)	136		(3)		336		(52)		221		(21)		249		(48)
Total Available-for-Sale Debt Securities	342		(9)		742		(128)		522		(48)		541		(115)
NDT Trust Investments	$	410	$	(16)	$	791	$	(145)	$	700	$	(70)	$	588	$	(133)

(A)Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. Unrealized gains and losses on these securities are recorded in Net Income.

(B)Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on PSEG Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. PSEG Power also has investments in municipal bonds. It is not expected that these securities will settle for less than their amortized cost. PSEG Power does not intend to sell these securities nor will it be more-likely-than-not required to sell before recovery of their amortized cost. PSEG Power did not recognize credit losses for U.S. Treasury obligations and Federal Agency mortgage-backed securities because these investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG Power did not recognize credit losses for municipal bonds because they are primarily investment grade securities.

(C)Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). Unrealized losses were due to market declines. It is not expected that these securities would settle for less than their amortized cost. PSEG Power does not intend to sell these securities nor will it be more-likely-than-not required to sell before recovery of their amortized cost. PSEG Power did not recognize credit losses for corporate bonds because they are primarily investment grade securities.

As of September 30, 2017 As of December 31, 2016

Less Than 12
Months

Greater Than 12
Months

Less Than 12
Months

Greater Than 12
Months

Fair
Value

Gross
Unrealized
Losses

Fair
Value

Gross
Unrealized
Losses

Fair
Value

Gross
Unrealized
Losses

Fair
Value

Gross
Unrealized
Losses

Millions
Equity Securities (A) $ 67
$ (5 ) $ —
$ —
$ 120
$ (10 ) $ 8
$ (1 )
Debt Securities
Government (B) 237
(2 ) 62
(2 ) 276
(6 ) 4
—

Corporate (C) 60
—
36
(1 ) 139
(3 ) 15
(1 )
Total Debt Securities 297
(2 ) 98
(3 ) 415
(9 ) 19
(1 )
Other Securities 3
—
—
—
—
—
—
—

NDT Available-for-Sale Securities $ 367
$ (7 ) $ 98
$ (3 ) $ 535
$ (19 ) $ 27
$ (2 )


~~(A)~~	Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over a broad range of securities with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of September 30, 2017.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

~~(B)~~

Debt Securities (Government)—Unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. Power also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of September 30, 2017.

~~(C)~~

Debt Securities (Corporate)—Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of September 30, 2017.

The proceeds from the sales of and the net ~~realized~~ gains (losses) on securities in the NDT Fund were:



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2023		2022		2023		2022
	Millions
Proceeds from NDT Fund Sales (A)	$	308	$	341	$	704	$	814
Net Realized Gains (Losses) on NDT Fund
Gross Realized Gains	$	25	$	21	$	46	$	50
Gross Realized Losses	(28)		(31)		(55)		(65)
Net Realized Gains (Losses) on NDT Fund (B)	(3)		(10)		(9)		(15)
Net Unrealized Gains (Losses) on Equity Securities	60		(170)		111		(231)

Net Gains (Losses) on NDT Fund Investments	$	57	$	(180)	$	102	$	(246)

Three Months Ended Nine Months Ended
September 30, September 30,
2017 2016 2017 2016
Millions
Proceeds from NDT Fund Sales (A) $ 278
$ 139
$ 845
$ 470

Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains $ 29
$ 11
$ 82
$ 36

Gross Realized Losses (5 ) (3 ) (14 ) (25 )
Net Realized Gains (Losses) on NDT Fund $ 24
$ 8
$ 68
$ 11

(A)Includes activity in accounts related to the liquidation of funds being transitioned ~~to new managers.~~within the trust.

(B)The cost of these securities was determined on the basis of specific identification.

Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in PSEG’s and Power’s Condensed Consolidated Statements of Operations. Net unrealized gains of ~~$172 million~~ ~~(after-tax) were recognized in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Condensed Consolidated Balance Sheets as of~~ ~~September 30, 2017~~.

The NDT ~~available-for-sale~~Fund debt securities held as of ~~September~~June 30, ~~2017~~2023 had the following maturities:



Time Frame	Fair Value
	Millions
Less than one year	$	20
1 - 5 years	293
6 - 10 years	220
11 - 15 years	66
16 - 20 years	101
Over 20 years	492
Total NDT Available-for-Sale Debt Securities	$	1,192

Time Frame Fair Value
Millions
Less than one year $ 37

1 - 5 years 236

6 - 10 years 230

11 - 15 years 62

16 - 20 years 67

Over 20 years 293

Total NDT Available-for-Sale Debt Securities $ 925

PSEG Power periodically assesses individual debt securities whose fair value is less than amortized cost to determine whether the investments are ~~considered to be other-than-temporarily~~ impaired. For ~~equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income~~these securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). ~~For the nine months ended September 30, 2017, Other-Than-Temporary Impairments (OTTI) of$9 million~~ ~~were recognized on securities in the NDT Fund.~~ Any subsequent recoveries inof the ~~value~~noncredit loss component of ~~these securities~~the impairment would be

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

~~recognized in~~ recorded through Accumulated Other Comprehensive Income (Loss) ~~unless~~. Any subsequent recoveries of the ~~securities are sold, in which case, any gain~~credit loss component would be recognized ~~in income.~~through earnings. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

Rabbi Trust

PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in a grantor trust commonly known as a “Rabbi Trust.”

~~PSEG classifies investments in the Rabbi Trust as available-for-sale.~~ The following tables show the fair values, gross unrealized gains and losses and amortized cost basis for the securities held in the Rabbi Trust.

As of September 30, 2017
Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value

Millions
Equity Securities $ 22
$ 1
$ —
$ 23

Debt Securities
Government 82
2
—
84

Corporate 118
3
(1 ) 120

Total Debt Securities 200
5
(1 ) 204

Other Securities 2
—
—
2

Total Rabbi Trust Available-for-Sale Securities $ 224
$ 6
$ (1 ) $ 229

As of December 31, 2016
Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value

Millions
Equity Securities $ 11
$ 11
$ —
$ 22

Debt Securities
Government 105
—
(2 ) 103

Corporate 92
1
(2 ) 91

Total Debt Securities 197
1
(4 ) 194

Other Securities 1
—
—
1

Total Rabbi Trust Available-for-Sale Securities $ 209
$ 12
$ (4 ) $ 217

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents



	As of June 30, 2023
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	Millions
Domestic Equity Securities	$	13	$	8	$	—	$	21
Available-for-Sale Debt Securities
Government	111		—		(19)		92
Corporate	85		—		(13)		72
Total Available-for-Sale Debt Securities	196		—		(32)		164

Total Rabbi Trust Investments	$	209	$	8	$	(32)	$	185



	As of December 31, 2022
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	Millions
Domestic Equity Securities	$	14	$	6	$	—	$	20
Available-for-Sale Debt Securities
Government	110		—		(21)		89
Corporate	89		—		(15)		74
Total Available-for-Sale Debt Securities	199		—		(36)		163
Total Rabbi Trust Investments	$	213	$	6	$	(36)	$	183

Net unrealized gains (losses) on debt securities of $(23) million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s Condensed Consolidated Balance Sheet as of June 30, 2023. The portion of net unrealized gains (losses) recognized during the second quarter and first six months of 2023 related to equity securities still held as of June 30, 2023 was $1 million and $2 million, respectively.

The amounts in the preceding tables do not include receivables and payables for Rabbi Trust Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets as shown in the following table.



	As of		As of
	June 30, 2023		December 31, 2022
	Millions
Accounts Receivable	$	1	$	1
Accounts Payable	$	1	$	—

As of As of
September 30,
2017 December 31,
2016
Millions
Accounts Receivable $ 2
$ 5

Accounts Payable $ —
$ 3

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

The following table shows the value of securities in the Rabbi Trust Fund that have been in an unrealized loss position for less than 12 months and greater than 12 months.

As of September 30, 2017 As of December 31, 2016

Less Than 12
Months

Greater Than 12
Months

Less Than 12
Months

Greater Than 12
Months

Fair
Value

Gross
Unrealized
Losses

Fair
Value

Gross
Unrealized
Losses

Fair
Value

Gross
Unrealized
Losses

Fair
Value

Gross
Unrealized
Losses

Millions
Equity Securities (A) $ —
$ —
$ —
$ —
$ —
$ —
$ —
$ —

Debt Securities
Government (B) 25
—
3
—
60
(2 ) 1
—

Corporate (C) 14
(1 ) 4
—
46
(2 ) 3
—

Total Debt Securities 39
(1 ) 7
—
106
(4 ) 4
—

Rabbi Trust Available-for-Sale Securities $ 39
$ (1 ) $ 7
$ —
$ 106
$ (4 ) $ 4
$ —



	As of June 30, 2023								As of December 31, 2022
	Less Than 12 Months				Greater Than 12 Months				Less Than 12 Months				Greater Than 12 Months
	Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses
	Millions
Available-for-Sale Debt Securities
Government (A)	$	16	$	(1)	$	75	$	(18)	$	32	$	(5)	$	57	$	(16)
Corporate (B)	14		(1)		55		(12)		35		(5)		39		(10)
Total Available-for-Sale Debt Securities	30		(2)		130		(30)		67		(10)		96		(26)

Rabbi Trust Investments	$	30	$	(2)	$	130	$	(30)	$	67	$	(10)	$	96	$	(26)


~~(A)~~	Equity Securities—Investments in marketable equity securities within the Rabbi Trust Fund are through a mutual fund which invests primarily in common stocks within a broad range of industries and sectors.

~~(B)~~

Debt Securities (Government)—Unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of September 30, 2017.

~~(C)~~

Debt Securities (Corporate)—PSEG’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of September 30, 2017.

(A)Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. PSEG also has investments in municipal bonds. It is not expected that these securities will settle for less than their amortized cost. PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell before recovery of their amortized cost. PSEG did not recognize credit losses for U.S. Treasury obligations and Federal Agency mortgage-backed securities because these investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG did not recognize credit losses for municipal bonds because they are primarily investment grade securities.

(B)Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). Unrealized losses were due to market declines. It is not expected that these securities would settle for less than their amortized cost. PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell before recovery of their amortized cost. PSEG did not recognize credit losses for corporate bonds because they are primarily investment grade.

The proceeds from the sales of and the net ~~realized~~ gains (losses) on securities in the Rabbi Trust Fund were:



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2023		2022		2023		2022
	Millions
Proceeds from Rabbi Trust Sales	$	11	$	20	$	17	$	48
Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains	$	3	$	2	$	4	$	3
Gross Realized Losses	(4)		(4)		(5)		(6)
Net Realized Gains (Losses) on Rabbi Trust (A)	(1)		(2)		(1)		(3)
Net Unrealized Gains (Losses) on Equity Securities	1		(5)		2		(6)

Net Gains (Losses) on Rabbi Trust Investments	$	—	$	(7)	$	1	$	(9)

Three Months Ended Nine Months Ended
September 30, September 30,
2017 2016 2017 2016
Millions
Proceeds from Rabbi Trust Sales (A) $ 24
$ 20
$ 168
$ 81

Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains $ —
$ 2
$ 17
$ 5

Gross Realized Losses (1 ) (2 ) (5 ) (4 )
Net Realized Gains (Losses) on Rabbi Trust $ (1 ) $ —
$ 12
$ 1

(A)~~Includes activity in accounts related to the liquidation of funds being transitioned to new managers.~~

The cost of these securities was determined on the basis of specific identification.

Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in the Condensed Consolidated Statements of Operations. Net unrealized gains of $3 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets as of ~~September 30, 2017~~.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

The Rabbi Trust ~~available-for-sale~~ debt securities held as of ~~September~~June 30, ~~2017~~2023 had the following maturities:

Time Frame Fair Value
Millions
Less than one year $ —

1 - 5 years 40

6 - 10 years 27

11 - 15 years 6

16 - 20 years 19

Over 20 years 112

Total Rabbi Trust Available-for-Sale Debt Securities $ 204



Time Frame	Fair Value
	Millions
Less than one year	$	7
1 - 5 years	25
6 - 10 years	20
11 - 15 years	10
16 - 20 years	14
Over 20 years	88
Total Rabbi Trust Available-for-Sale Debt Securities	$	164

PSEG periodically assesses individual debt securities whose fair value is less than amortized cost to determine whether the investments are considered to be ~~other-than-temporarily~~ impaired. For ~~equity securities, the Rabbi Trust is invested in an indexed mutual fund. Due to the commingled nature of this fund, PSEG does not have the ability to hold~~ these ~~securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For fixed income~~ securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). ~~For~~Any subsequent recoveries of the ~~nine months ended September 30, 2017, no OTTIs were~~noncredit loss component of the impairment would be recorded through Accumulated Other Comprehensive Income (Loss). Any subsequent recoveries of the credit loss component would be recognized ~~on securities in the Rabbi Trust.~~through earnings. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

The fair value of the Rabbi Trust related to ~~PSEG,~~ PSE&G and PSEG Power ~~are~~& Other is detailed as follows:



	As of		As of
	June 30, 2023		December 31, 2022
	Millions
PSE&G	$	33	$	32
PSEG Power & Other	152		151
Total Rabbi Trust Investments	$	185	$	183

As of As of
September 30,
2017 December 31,
2016
Millions
PSE&G $ 46
$ 43

Power 57
53

Other 126
121

Total Rabbi Trust Available-for-Sale Securities $ 229
$ 217

Note 8.9. Pension and Other Postretirement Benefits (OPEB)

PSEG sponsors and Services administers qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria.

AsPSEG and PSE&G are required to record the under or over funded positions of ~~December 31, 2016, PSEG merged its three qualified~~their defined benefit pension and OPEB plans ~~(excluding Servco plans) into one plan, thereby also merging all~~on their respective balance sheets. Such funding positions are required to be measured as of the ~~pension plans’ assets. As a result, the total net periodic benefit costs, net~~date of amounts capitalized, decreased by approximately $12 million and $36 million for the three months and nine months, ended September 30, 2017, respectively, as compared to the 2017 amounts that would have been recognized had the plans not been merged. This is due to the amortization period for gains and losses for the merged plan resulting in lower amortization than that of the individual plans. No changes were made to the benefit formulas, vesting provisions, or to the employees covered by the plans.their respective year-end Consolidated Balance Sheets.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

The following table provides the components of net periodic benefit costs (credits) relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis for PSEG, excluding Servco. Net periodic benefit costs are reduced in 2023 as a result of an accounting order from the BPU authorizing PSE&G to modify its method for calculating the amortization of the net actuarial gain or loss component of pension expense for rate making purposes. See Note 5. Rate Filings. Amounts shown do not reflect the impacts of capitalization, co-owner allocations and the 2023 BPU accounting order. Only the service cost component is eligible for capitalization, when applicable.

Pension Benefits OPEB Pension Benefits OPEB
Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended
September 30, September 30, September 30, September 30,
2017
2016 2017
2016 2017 2016 2017 2016
Millions
Components of Net Periodic Benefit Costs
Service Cost $ 29
$ 28
$ 4
$ 5
$ 86
$ 82
$ 12
$ 13

Interest Cost 51
50
15
15
153
151
47
44

Expected Return on Plan Assets (98 ) (98 ) (8 ) (8 ) (295 ) (295 ) (25 ) (23 )
Amortization of Net
Prior Service Cost (Credit) (5 ) (5 ) (3 ) (4 ) (14 ) (14 ) (8 ) (11 )
Actuarial Loss 24
39
13
10
73
118
38
30

Total Benefit Costs $ 1
$ 14
$ 21
$ 18
$ 3
$ 42
$ 64
$ 53

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents



	Pension Benefits				OPEB				Pension Benefits				OPEB
	Three Months Ended				Three Months Ended				Six Months Ended				Six Months Ended
	June 30,				June 30,				June 30,				June 30,
	2023		2022		2023		2022		2023		2022		2023		2022
	Millions
Components of Net Periodic Benefit (Credits) Costs
Service Cost (included in O&M Expense)	$	23	$	36	$	1	$	1	$	45	$	71	$	2	$	3
Non-Service Components of Pension and OPEB (Credits) Costs
Interest Cost	69		41		11		7		138		83		21		13
Expected Return on Plan Assets	(96)		(121)		(9)		(10)		(191)		(242)		(17)		(21)
Amortization of Net
Prior Service Credit	—		—		(13)		(32)		—		—		(26)		(64)
Actuarial Loss (Gain)	24		15		—		3		48		30		(1)		7
Non-Service Components of Pension and OPEB (Credits) Costs	(3)		(65)		(11)		(32)		(5)		(129)		(23)		(65)
Total Benefit (Credits) Costs	$	20	$	(29)	$	(10)	$	(31)	$	40	$	(58)	$	(21)	$	(62)

Pension and OPEB (credits) costs for PSE&G and PSEG Power ~~and PSEG’s other subsidiaries, excluding Servco,~~& Other are detailed as follows:



	Pension Benefits				OPEB				Pension Benefits				OPEB
	Three Months Ended				Three Months Ended				Six Months Ended				Six Months Ended
	June 30,				June 30,				June 30,				June 30,
	2023		2022		2023		2022		2023		2022		2023		2022
	Millions
PSE&G	$	14	$	(17)	$	(10)	$	(28)	$	27	$	(35)	$	(20)	$	(55)
PSEG Power & Other	6		(12)		—		(3)		13		(23)		(1)		(7)
Total Benefit (Credits) Costs	$	20	$	(29)	$	(10)	$	(31)	$	40	$	(58)	$	(21)	$	(62)

PSEG does not plan to contribute to its pension and OPEB plans in 2023.

In July 2023, PSEG and Fiduciary Counselors Inc., as independent fiduciary of the Pension Plan of Public Service Enterprise Group Incorporated and Pension Plan of Public Service Enterprise Group Incorporated II (together, the Plans), entered into a commitment agreement (for a “lift-out”) with The Prudential Insurance Company of America (the Insurer) under which the Plans agreed to purchase a nonparticipating single premium group annuity contract that will transfer to the Insurer approximately $1 billion of the Plans’ defined benefit pension obligations and associated Plan assets related to certain pension benefits. The contract covers approximately 2,000 retirees from PSEG Power & Other, excluding Services (Participants). To the extent provided in the contract, the Insurer has made an irrevocable commitment, and will be solely responsible, to pay benefits of each Participant that are due on and after December 31, 2023. The transaction will result in no changes to the amount of benefits payable to Participants.

As a result of the transaction, PSEG expects to recognize a one-time settlement charge in the range of $315 million to $360 million ($225 million to $260 million, net of tax) in the third quarter of 2023 related to the immediate recognition of unamortized net actuarial loss associated with the portion of the pension involved in the transaction. The charge is subject to finalization based on actuarial and other assumptions. PSEG expects the transaction to be completed in August 2023, subject to the satisfaction of closing conditions.

Pension Benefits OPEB Pension Benefits OPEB
Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended
September 30, September 30, September 30, September 30,
2017 2016 2017 2016 2017 2016 2017 2016
Millions
PSE&G $ (1 ) $ 8
$ 13
$ 11
$ (3 ) $ 22
$ 40
$ 33

Power —
3
7
6
1
11
20
17

Other 2
3
1
1
5
9
4
3

Total Benefit Costs $ 1
$ 14
$ 21
$ 18
$ 3
$ 42
$ 64
$ 53

~~During the three months ended March 31, 2017, PSEG contributed its entire planned contribution for the year 2017~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of ~~$14 million into its OPEB plan.~~Contents

Servco Pension and OPEB

~~At the direction of LIPA,~~ Servco sponsors ~~benefit plans that cover~~a qualified pension plan and OPEB plan covering its ~~current and former~~ employees who meet certain eligibility criteria. Under the OSA, ~~all of these and any future~~ employee benefit costs for these plans are ~~to be~~ funded by LIPA. See Note 4. Variable Interest Entity. These obligations, as well as the offsetting long-term receivable, are separately presented on the Condensed Consolidated Balance Sheet of PSEG.

Servco amounts are not included in any of the preceding pension and OPEB ~~benefit~~ cost disclosures. Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. Servco’s pension-related revenues and costs were ~~$18~~$4 million and ~~$16~~$7 million for the three months ended ~~September~~June 30, ~~2017~~2023 and ~~2016,~~2022, respectively, and ~~$35~~$9 million and ~~$28~~$15 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016,~~2022, respectively. ~~Servco’s pension-related costs of $35 million for the nine months ended September 30, 2017 represent its entire planned contribution for the year 2017.~~ The OPEB-related revenues earned and costs incurred were ~~$1 million and~~ $3 million for each of the three months ended June 30, 2023 and ~~nine~~2022, and $6 million and $5 million for the six months ended ~~September~~June 30, ~~2017. The OPEB-related revenues earned~~2023 and ~~costs incurred were immaterial for the three months and nine months ended September 30, 2016.~~2022, respectively.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~Servco plans to contribute $18 million to its pension plan in 2023.

~~(UNAUDITED)~~

~~Table of Contents~~

Note 9.10. Commitments and Contingent Liabilities

Guaranteed Obligations

PSEG Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees as a form of collateral.

PSEG Power has unconditionally guaranteed payments to counterparties byon behalf of its subsidiaries in commodity-related transactions in order to

•support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and

•obtain credit.

PSEG Power is subject to

•counterparty collateral calls related to commodity contracts of its subsidiaries, and

•certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries.

Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction.

In order for PSEG Power to incur a liability for the face value of the outstanding guarantees,

•its subsidiaries would have to

fully utilize the credit granted to them by every counterparty to whom PSEG Power has provided a guarantee, and

•the net position of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, PSEG Power would owe money to the counterparties).

PSEG Power believes the probability of this result is unlikely. For this reason, PSEG Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. Current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.

Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. PSEG Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules.

In addition to the guarantees discussed above, PSEG Power has also provided payment guarantees to third parties and regulatory authorities on behalf of its affiliated companies. These guarantees support various other non-commodity related ~~contractual~~ obligations.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

The following table shows the face value of PSEG Power’s outstanding guarantees, current exposure and margin positions as of ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016.~~2022.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

As of As of
September 30,
2017 December 31,
2016
Millions
Face Value of Outstanding Guarantees $ 1,846
$ 1,806

Exposure under Current Guarantees $ 108
$ 139

Letters of Credit Margin Posted $ 134
$ 157

Letters of Credit Margin Received $ 59
$ 99

Cash Deposited and Received:
Counterparty Cash Margin Deposited $ —
$ —

Counterparty Cash Margin Received $ (2 ) $ (1 )
Net Broker Balance Deposited (Received) $ (6 ) $ 57

Additional Amounts Posted:
Other Letters of Credit $ 61
$ 51



	As of		As of
	June 30, 2023		December 31, 2022
	Millions
Face Value of Outstanding Guarantees	$	1,445	$	1,601
Exposure under Current Guarantees	$	80	$	198

Letters of Credit Margin Posted	$	13	$	87
Letters of Credit Margin Received	$	85	$	38

Cash Deposited and Received
Counterparty Cash Collateral Deposited	$	—	$	—
Counterparty Cash Collateral Received	$	(7)	$	(1)
Net Broker Balance Deposited (Received)	$	433	$	1,522

Additional Amounts Posted
Other Letters of Credit	$	180	$	156

As part of determining credit exposure, PSEG Power nets receivables and payables with the corresponding net fair values of energy ~~contract balances.~~contracts. See Note ~~11.~~12. Financial Risk Management Activities for further discussion. In accordance with PSEG’s accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Condensed Consolidated Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively.

In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and PSEG Power have posted letters of credit to support PSEG Power’s various other non-energy contractual and environmental obligations. See the preceding table. PSEG also issued a $21 million guarantee to support Power’s payment obligations related to construction of a 755 MW gas-fired combined cycle generating station in Maryland. In the event that PSEG were to be downgraded to below investment grade and failed to meet minimum net worth requirements, these guarantees would each have to be replaced by a letter of credit. In June 2017, Power sold its minority equity interest in PennEast and upon disposition, PSEG’s $106 million guarantee that had supported Power’s obligations related to PennEast was terminated.

Environmental Matters

Passaic River

~~Historic operations~~Lower Passaic River Study Area

The U.S. Environmental Protection Agency (EPA) has determined that a 17-mile stretch of ~~PSEG companies and the operations of hundreds of other companies along~~ the Passaic ~~and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into~~River (Lower Passaic River Study Area (LPRSA)) in New Jersey is a “Superfund” site under the ~~Passaic River/Newark Bay Complex in violation of various statutes as discussed as follows.~~

Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA)

In 2002, the EPA determined that a 17-mile stretch of the lower Passaic River from Newark to Clifton, New Jersey is a “Superfund” site under CERCLA. This designation allows the EPA to clean up such sites and to compel responsible parties to perform cleanups or reimburse the government for cleanups led by the EPA.

~~The EPA determined that there was a need to perform a comprehensive study of the entire 17 miles of the lower Passaic River.~~. PSE&G and certain of its predecessors conducted operations at properties in this area, ~~of the Passaic River. The properties included~~including at one ~~operating electric generating station (Essex Site), which~~site that was transferred to PSEG Power.

The EPA has announced two separate cleanup plans for the Lower 8.3 miles and Upper 9 miles of the LPRSA. The EPA’s plan for the Lower 8.3 miles involves dredging and capping sediments at an estimated cost of $2.3 billion, and its plan for the Upper 9 miles involves dredging and capping sediments at an estimated cost of $550 million. Additional cleanup work may be required depending on the results of these initial phases of work.

Occidental Chemical Corporation (Occidental) has voluntarily commenced design of the cleanup plan for the Lower 8.3 miles, and has received an EPA Unilateral Administrative Order directing it to design the cleanup plan for the Upper 9 miles. It has filed two lawsuits against PSE&G and others to attempt to recover costs associated with this work and to obtain a declaratory judgement of parties’ shares of any future costs. One lawsuit is currently paused, and the other is currently proceeding. PSEG cannot predict the outcome of the litigation.

The EPA has announced a proposed settlement with 85 parties who have agreed to pay $150 million to resolve their LPRSA CERCLA liability, in whole or in part. It is uncertain whether the settlement will be finalized as currently proposed. PSE&G and PSEG Power ~~one former generating station~~are not included in the proposed settlement, but the EPA sent PSE&G, Occidental, and ~~four former manufactured gas plant (MGP) sites.~~

~~In early 2007, 73~~several other Potentially Responsible Parties (PRPs)~~, including~~ a letter in March 2022 inviting them to submit to the EPA individually or jointly an offer to fund or participate in the next stages of the remediation. PSEG submitted a good faith offer to the EPA in June 2022 on behalf of PSE&G and ~~Power, formed~~PSEG Power. PSEG understands that the EPA is evaluating its offer.

Two PRPs, Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus), have filed for Chapter 11 bankruptcy. The trust representing the creditors in this proceeding has filed a ~~Cooperating Parties Group (CPG)~~complaint asserting claims against Tierra’s and ~~agreed~~Maxus’ current and former parent entities, among others. Any damages awarded may be used to ~~assume responsibility for conducting a Remedial Investigation and Feasibility Study (RI/FS)~~fund the remediation of the ~~17 miles of the lower Passaic River. At such time, the CPG also agreed to allocate, on an interim basis, the associated costs of the~~LPRSA.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

~~RI/FS among~~As of June 30, 2023, PSEG has approximately $66 million accrued for this matter. PSE&G has an Environmental Costs Liability of $53 million and a corresponding Regulatory Asset based on its ~~members on the basis of a mutually agreed upon formula. For the purpose of this interim allocation, which has been revised as parties have exited the CPG, approximately seven percent~~assessment of the RI/FS costs are currently deemed attributable to PSE&G’s former MGP sites and approximately one percent is attributable to Power’s generating stations. These interim allocations are not binding on PSE&G or Power in terms of their respective shares of the costs that will be ultimately required to remediate the 17 miles of the lower Passaic River. PSEG has provided notice to insurers concerning this potential claim.

In June 2008, the EPA and Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus) entered into an early action agreement whereby Tierra/Maxus agreed to remove a portion of the heavily dioxin-contaminated sediment located in the lower Passaic River. The portion of the Passaic River identified in this agreement was located immediately adjacent to Tierra/Maxus’ predecessor company’s (Diamond Shamrock) facility. Pursuant to the agreement between the EPA and Tierra/Maxus, the estimated cost for the work to remove the sediment in this location was $80 million. Phase I of the removal work has been completed. Pursuant to this agreement, Tierra/Maxus have reserved their rights to seek contribution for these removal costs from the other PRPs, including Power and PSE&G.

In 2012, Tierra/Maxus withdrew from the CPG and refused to participate as members going forward, other than with respect to their obligation to fund the EPA’s portion of its RI/FS oversight costs. At such time, the remaining members of the CPG, in agreement with the EPA, commenced the removal of certain contaminated sediments at Passaic River Mile 10.9 at an estimated cost of $25 million to $30 million. Construction is complete. The CPG is awaiting EPA approval of the construction report, long-term monitoring plan and confirmatory sampling plan. PSE&G’s and Power’s combined share of the cost of that effort is approximately three percent. The remaining CPG members, PSE&G and Power included, have reserved their rights to seek reimbursement from Tierra/Maxus for the costs of the River Mile 10.9 removal.

On April 11, 2014, the EPA released its revised draft “Focused Feasibility Study” (FFS) which contemplates the removal of 4.3 million cubic yards of sediment from the bottom of the lower eight miles of the 17-mile stretch of the Passaic River. The revised draft FFS sets forth various alternatives for remediating this portion of the Passaic River.

The CPG, which consisted of 50 members as of September 30, 2017, provided a draft RI and draft FS, both relating to the entire 17 miles of the lower Passaic River, to the EPA on February 18, 2015 and April 30, 2015, respectively. The estimated total cost of the RI/FS is approximately $195 million, which the CPG continues to incur. Of the estimated $195 million, as of September 30, 2017, the CPG had spent approximately $168 million, of which PSEG’s total share was approximately $12 million.

The CPG’s draft FS set forth various alternatives for remediating the lower Passaic River. It set forth the CPG’s estimated costs to remediate the lower 17 miles of the Passaic River which range from approximately $518 million to $3.2 billion on an undiscounted basis. The CPG identified a targeted remedy in the draft FS which would involve removal, treatment and disposal of contaminated sediments taken from targeted locations within the entire 17 miles of the lower Passaic River. The estimated cost in the draft FS for the targeted remedy ranged from approximately $518 million to $772 million. Based on (i) the low end of the range of the current estimates of costs to remediate, (ii) PSE&G’s and Power’s estimated share of those costs, and (iii) the continued ability ~~of PSE&G~~ to recover such costs in its ~~rates, PSE&G accrued~~rates. PSEG Power has an Environmental Liability of $13 million.

The outcome of this matter is uncertain, and until (i) a ~~$10 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued a $3 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2015.~~

~~In March 2016, the EPA released its Record of Decision (ROD)~~final remedy for the FFS which requires the removal of 3.5 million cubic yards of sediment from the Passaic River’s lower 8.3 miles at an estimated cost of $2.3 billion on an undiscounted basis (ROD Remedy). The ROD Remedy requires a bank-to-bank dredge ranging from approximately 5 to 30 feet deep in the federal navigation channel from River Mile 0 to River Mile 1.7entire LPRSA is selected and an approximately 2.5 foot deep dredge everywhere else in the lower 8.3 miles of the river. An engineered cap approximately two feet thick will be placed over the dredged areas. Dredged sediments will be transported to facilities and landfills out-of-state. The EPA estimates the total project length to be about 11 years, including a one year period of negotiation with the PRPs, three to four years to design the project and six years for implementation.

Based upon the estimated cost of the ROD Remedy, PSEG’s estimate of PSE&G’s and Power’s shares of that cost, and the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued an additional $36 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued an additional $8 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2016. These accruals brought the total liability to approximately $57 million, $46 million applicable to PSE&G and $11 million applicable to Power. There have been no additional accruals recorded since the first quarter of 2016.

Also in March 2016, the EPA sent a notice letter to 105 PRPs, including PSE&G, all other past and present members of the CPG, including Occidental Chemical Corporation (OCC), and the towns of Newark, Kearny and Harrison and the Passaic Valley Sewerage Commission stating that the EPA wants to determine whether OCC, a successor company to Diamond Shamrock, would voluntarily perform the remedial design for the ROD Remedy. On September 30, 2016, OCC and the EPA

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

executed an Administrative Settlement Agreement and Order on Consent for Remedial Design under which OCC agreed to conduct the remedial design for the ROD. With OCC’s commitment to perform the remedial design, itagreement is anticipated that the EPA will begin negotiation of a remedial action consent decree, under which OCC and the other “major PRPs” will implement and/or pay for the EPA’s ROD Remedy for the lower 8.3 miles. The EPA has not defined “major PRPs.”

In June 2016, Tierra and Maxus, successors to Diamond Shamrock, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Maxus and Tierra are subsidiaries of YPF Holdings, Inc. (YPF Holdings). YPF Holdings is a wholly owned subsidiary of YPF S.A. (YPF), a company controlled by the Argentinian government. Neither YPF Holdings nor YPF is a party to the bankruptcy proceedings. However, Tierra and Maxus have filed a plan of liquidation that may allow the parties to assert one or more causes of action to hold YPF responsible for certain amounts owed by Tierra and Maxus. The bankruptcy plan ordered by the Delaware Court in July, 2017 created a Liquidating Trust to pursue outstanding creditors’ claims, including alter ego claims against YPF. PSEG cannot currently determine the impact, if any, that the bankruptcy of Tierra and Maxus or any related proceeding might have on its allocable share or total liability for the Passaic River matter, and therefore, PSEG, through the CPG and independently, will continue to monitor the bankruptcy proceedings to identify any potential impact on PSEG’s share of the costs.

In March 2017, the EPA sent a letter to certain PRPs that are considered by the EPA to have minimal responsibility for the Passaic River’s contamination, offering “cash-out” settlements. The PRPs that settle will be released from their CERCLA remediation liability for the lower 8.3 miles of the lower Passaic River. The impact of this proposed settlement on PSEG’s responsibility for the remediation of the lower 8.3 miles is not material.

In September 2017, the EPA concluded that an Agency-commenced allocation process for the Passaic River’s lower 8.3 miles should include only certain PRPs that received General Notice letters (excluding PRPs that settle pursuant to the early cash-out settlement that the EPA offered in March 2017, among others). The allocation is intended to lead to a consent decree in which certain of the PRPs agree to perform the remedial action under EPA oversight. Discussions on the matter are ongoing.

The EPA has broad authority to implement its selected remedy through the ROD and PSEG cannot at this time predict how the implementation of the ROD might impact PSE&G’s and Power’s ultimate liability. Until (i) the RI/FS, which covers the entire 17 miles of the lower Passaic River, is finalized either in whole or in part, (ii) an agreementreached by the PRPs to ~~perform either the ROD Remedy as issued, or an amended ROD Remedy determined through negotiation or litigation, and an agreed upon remedy for the remaining 8.7 miles of the river, are reached, (iii)~~fund it, (ii) PSE&G’s and PSEG Power’s respective shares of the costs ~~both in the aggregate as well as individually,~~ are determined, and ~~(iv)~~(iii) PSE&G’s ~~continued~~ ability to recover the costs in its rates is determined, it is not possible to predict this matter’s ultimate impact on PSEG’s financial statements. It is possible that PSE&G and PSEG Power will record additional costs beyond what they have accrued, and that such costs could be material, but PSEG cannot at the current time estimate the amount or range of any additional costs.

~~Natural Resource Damage Claims~~

In 2003, the New Jersey Department of Environmental Protection (NJDEP) directed PSEG, PSE&G and 56 other PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the New Jersey Spill Compensation and Control Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million. In 2007, agencies of the U.S. Department of Commerce and the U.S. Department of the Interior (the Passaic River federal trustees) sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter.

Newark Bay Study Area

The EPA has established the Newark Bay Study Area, which ~~it defines as~~is an extension of the LPRSA and includes Newark Bay and portions of ~~the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the~~surrounding waterways. The EPA ~~sent~~has notified PSEG and 1121 other ~~entities notices that it considered each~~PRPs of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but PSEG has not consented to fund the third phase.their potential liability. PSE&G and PSEG Power are unable to estimate their respective portions of any loss or possible range of loss related to this matter. In December 2018, PSEG Power completed the sale of the site of the Hudson electric generating station. PSEG Power contractually transferred all land rights and structures on the Hudson site to a third-party purchaser, along with the assumption of the environmental liabilities for the site.

Natural Resource Damage Claims

New Jersey and certain federal regulators have alleged that PSE&G, PSEG Power and 56 other PRPs may be liable for natural resource damages within the LPRSA. In particular, PSE&G, PSEG Power and other PRPs received notice from federal regulators of the regulators’ intent to move forward with a series of studies assessing potential damages to natural resources at the Diamond Alkali Superfund Site, which includes the LPRSA and the Newark Bay Study Area. PSE&G and PSEG Power are unable to estimate their respective portions of any possible loss or range of loss related to this matter.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~Hackensack River

~~(UNAUDITED)~~

~~Table~~In 2022, the EPA announced it had designated the lower 18.75 miles of ~~Contents~~

the Hackensack River a federal Superfund site. PSE&G and certain of its predecessors conducted operations at properties in this area, including at the Hudson, Bergen and Kearny generating stations that were transferred to PSEG Power. PSEG Power subsequently contractually transferred all land rights and structures on the Hudson generating station site to a third-party purchaser, along with the assumption of the environmental liabilities for that site. The ultimate impact of this action on PSE&G and PSEG Power is currently unknown, but could be material.

MGP Remediation Program

PSE&G is working with the ~~NJDEP~~New Jersey Department of Environmental Protection (NJDEP) to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between ~~$390~~$198 million and ~~$440~~$219 million on an undiscounted basis, ~~through2021,~~ including its ~~$46~~$53 million share for the Passaic River as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of ~~$390~~$198 million as of~~September~~June 30, ~~2017.~~2023. Of this amount, ~~$74~~$39 million was recorded in Other Current Liabilities and ~~$316~~$159 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a ~~$390~~$198 millionRegulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. ~~NJDEP, PSEG and EPA representatives have had discussions regarding to what extent~~PSE&G completed sampling in the Passaic River ~~is required~~in 2020 to delineate coal tar from certain MGP sites that abut the Passaic River Superfund site. PSEG cannot determine at this time ~~whether this will have an~~the magnitude of any impact on the Passaic River Superfund remedy.

~~Prevention of Significant Deterioration (PSD)/New Source Review (NSR)~~Legacy Environmental Obligations at Former Fossil Generating Sites

~~The PSD/NSR regulations, promulgated under the Clean Air Act (CAA), require major sources~~PSEG Power has retained ownership of certain ~~air pollutants~~liabilities excluded from the 2022 sale of its fossil generation portfolio. These liabilities primarily relate to obtain permits, install pollution control technology and obtain offsets, in some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The federal government may order companies that are not in compliance with the PSD/NSR regulations to install the best available control technology at the affected plants and to pay monetary penalties ranging from $25,000 to $37,500 per day for each violation, depending upon when the alleged violation occurred.

In 2009, the EPA issued a notice of violation to Power and the other owners of the Keystone coal-fired plant in Pennsylvania, alleging, among other things, that various capital improvement projects were completed at the plant which are considered modifications (or major modifications) causing significant net emission increases of PSD/NSR air pollutants, beginning in 1985 for Keystone Unit 1 and in 1984 for Keystone Unit 2. The notice of violation states that none of these modifications underwent the PSD/NSR permitting process prior to being put into service, which the EPA alleges was required under the CAA. The notice of violation states that the EPA may issue an order requiring compliance with the relevant CAA provisions and may seek injunctive relief and/or civil penalties. Power owns approximately 23% of the plant. Power cannot predict the outcome of this matter.

~~Clean Water Act (CWA) Permit Renewals~~

Pursuant to the Federal Water Pollution Control Act, National Pollutant Discharge Elimination System permits expire within five years of their effective date. In order to renew these permits, but allow a plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. States with delegated federal authority for this program manage these permits. The NJDEP manages the permitsobligations under the New Jersey ~~Pollutant Discharge Elimination System (NJPDES) program.~~ISRA and the CTA to investigate and remediate PSEG Power’s two formerly owned generating station sites in Connecticut, and six formerly owned generating station sites in New ~~York also have permits~~Jersey. In addition, PSEG Power still owns two former generating station sites in New Jersey that triggered ISRA in 2015.

PSEG Power is in the process of fulfilling its obligations under ISRA and the CTA to ~~manage their respective pollutant discharge elimination system programs.~~investigate these sites. It will require multiple years and comprehensive environmental sampling to understand the extent of and to carry out the required remediation. The full remediation costs at each of the ten sites are not estimable, but will likely be material.

~~In May 2014, the EPA issued a final~~CWA Section 316(b) Rule

The EPA’s CWA Section 316(b) rule ~~that~~ establishes ~~new~~ requirements for the ~~regulation~~design and operation of cooling water intake structures at

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

existing power plants and industrial facilities with a design flow of more than two million gallons of water per day.

The EPA has structured the rule so that each state Permitting Director will continue to consider renewal permits for existing power facilities on a case by case basis. In connection with the assessment of the best technology available for minimizing adverse environmental impacts of each facility that seeks a permit renewal, the rule requires that facilities conduct a wide range of studies related to impingement mortality and entrainment and submit the results with their permit applications.

In September 2014, several environmental non-governmental groups and certain energy industry groups filed petitions for review of the rule and the case has been assigned to the U.S. Court of Appeals for the Second Circuit (Second Circuit). Environmental organizations, including but not limited to the environmental petitioners in the Second Circuit, have also filed suit under the Endangered Species Act. The cases were subsequently consolidated at the Second Circuit and a decision remains pending.

In June 2016, the NJDEP issued a final ~~NJPDES~~New Jersey Pollutant Discharge Elimination System permit for Salem with an effective date of August 1, 2016. The final permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the CWA, it requires additional studies and the selection of technology to address impingement for the service water system.Salem. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed aan administrative hearing request challenging certain conditions of the permit, including the NJDEP’s ~~issuance~~application of the ~~final permit for Salem. This matter is still pending. The Riverkeeper’s filing does not change the effective date of the permit.~~316(b) rule. If the Riverkeeper’s challenge ~~were~~is successful, PSEG Power may be required to incur additional costs to comply with

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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the CWA. Potential cooling water and/or service water system modification costs could be material and could adversely impact the economic competitiveness of this facility.

~~State permitting decisions at Bridgeport~~ The NJDEP granted the hearing request and ~~possibly New Haven could also have~~may schedule a ~~material impact on Power’s ability to renew permits at its existing larger once-through cooled plants without making significant upgrades to existing intake structures and cooling systems.~~

~~Power is unable to predict the outcome of these permitting decisions and the effect, if any, that they may have on Power’s future capital requirements, financial condition or results of operations.~~

Power is actively engaged with the Connecticut Department of Energy and Environmental Protection (CTDEEP) regarding renewal of the current permit for the cooling water intake structure at BH3. To address compliance with the EPA’s CWA Section 316(b) final rule, the current proposal under consideration is that, if a final permit is issued, Power would continue to operate BH3 without making the capital expenditures for modification to the existing intake structure and retire BH3 in 2021, which is four years earlier than the previously estimated useful life ending in 2025. Power is currently awaiting action by the CTDEEP to issue a draft and then a final permit.

Separately, Power has also negotiated a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, Connecticut and local community organizations. That CEBA provides that Power would retire BH3 early if all its precedent conditions occur, which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same site that BH3 currently operates. Absent those conditions being met, and the permit for the cooling water intake structure referred to above not being issued, Power may seek to operate BH3 through the previously estimated useful life.

In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. The Connecticut Siting Council (CSC) issued an order to approve siting Bridgeport Harbor Station unit 5. All major environmental permits have been received; however, secondary approvals are still being obtained to allow operations to begin by June 2019. Power’s obligations under the CEBA are being monitored regularly and carried out as needed.

~~Bridgeport Harbor National Pollutant Discharge Elimination System (NPDES) Permit Compliance~~

In April 2015, Power determined that monitoring and reporting practices related to certain permitted wastewater discharges at its Bridgeport Harbor station may have violated conditions of the station’s NPDES permit and applicable regulations and could subject it to fines and penalties. Power has notified the CTDEEP of the issues and has taken actions to investigate and resolve the potential non-compliance. Power cannot predict the impact of this matter.hearing after considering dispositive motions.

Jersey City, New Jersey Subsurface Feeder Cable Matter

In ~~early~~ October 2016, a discharge of dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the NJDEP. The feeder cables are located within a subsurface easement granted to PSE&G by the property owners, Newport Associates Development Company (NADC) and Newport Associates Phase I Developer Limited Partnership. The feeder cables are subject to agreements between PSE&G and Consolidated Edison Company of New York, Inc. (Con Edison) and are jointly owned by PSE&G and Con Edison, with PSE&G owning the portion of the cables located in New Jersey and Con Edison owning the portion of the cables located in New York. The NJDEP has declared an emergency and an emergency response action has been undertaken to investigate, contain, remediate and stop the fluid discharge; to assess, repair and restore the cables to good working order, if feasible; and to restore the property. The regulatory agencies overseeing the emergency response, including the U.S. Coast Guard, the NJDEP and the Army Corps of Engineers, have issued multiple notices, orders and directives to the various parties related to this matter.Edison. The impacted cable was repaired in ~~late-September 2017; however,~~September 2017. A federal response was initially led by the ~~investigation and~~U.S. Coast Guard. The U.S. Coast Guard transitioned control of the federal response ~~actions related~~ to the EPA, and the EPA ended the federal response to the matter in 2018. The investigation of small amounts of residual dielectric fluid ~~discharge are ongoing. Also~~believed to be contained with the marina sediment is ongoing as part of the NJDEP site remediation program. In August 2020, PSE&G finalized a settlement with the federal government regarding the reimbursement of costs associated with the federal response to this matter and payment of civil penalties of an immaterial amount.

A lawsuit in federal court is ~~the process~~pending to determine ultimate responsibility for the costs to address the leak among PSE&G, Con Edison and NADC. In addition, Con Edison filed counter claims against PSE&G and NADC, including ~~an action filed by PSE&G in New Jersey federal court~~ seeking ~~damages from NADC.~~injunctive relief and damages. Based on theinformation currently available and depending on the outcome of the ~~New Jersey~~ federal court action, PSE&G’s portion of the costs to address the leak may be material; however, PSE&G anticipates that it will recover ~~these~~its costs, other than civil penalties, through regulatory proceedings.

~~Steam Electric Effluent Guidelines~~

In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater, and gasification wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power’s Bridgeport Harbor station and the jointly-owned Keystone and

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~~Conemaugh stations, have bottom ash transport water discharges that are regulated under this rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the rule.~~

In April 2017, the EPA announced that it had granted a petition for reconsideration of the ELG Rule and issued an administrative stay of the compliance dates in the rule that were the subject of pending litigation. In June 2017, the EPA proposed a rule to postpone the compliance deadlines for the BAT limitations for the aforementioned waste streams.In September 2017, the EPA issued a rule postponing for two years compliance dates solely related to bottom ash transport water and flue gas desulfurization wastewater. The EPA has announced plans to issue a new rule by November 2020 addressing revised requirements and compliance dates for these two waste streams. Power is unable to determine how this will ultimately impact its compliance requirements or its financial condition and results of operations.

Basic Generation Service (BGS), BGSS and ~~Basic Gas Supply Service (BGSS)~~ZECs

Each year, PSE&G obtains its electric supply requirements through ~~the~~ annual New Jersey BGS auctions for two categories of customers ~~who~~that choose not to purchase electric supply from ~~third party~~third-party suppliers. The first category ~~which represents about 80% of PSE&G’s load requirement,~~ is residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category is larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial Energy Pricing (CIEP)). Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master ~~Agreement~~Agreements with the winners of these RSCP and CIEP BGS auctions ~~following the BPU’s approval of the auction results. PSE&G has entered into contracts with winning BGS suppliers, including Power,~~ to purchase BGS for PSE&G’s load requirements. The winners of the ~~auction (including Power)~~RSCP and CIEP auctions are responsible for fulfilling all the requirements of a PJM ~~Load Serving Entity~~load-serving entity including the provision of capacity, energy, ancillary services ~~transmission~~ and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards.

The BGS-CIEP auction is for a one-year supply period from June 1 to May 31 with the BGS-CIEP auction price measured in dollars per MW-day for capacity. The final price for the BGS-CIEP auction year commencing June 1, ~~2016~~2023 is ~~$276.83~~$330.72 per MW-day, replacing the BGS-CIEP auction year price ending May 31, ~~2016~~2023 of ~~$335.33~~$276.26 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period.

PSE&G contracts for its anticipated BGS-RSCP load on a three-year rolling basis, whereby each year one-third of the load is procured for a three-year period. The contract prices in dollars per MWh for the BGS-RSCP supply, as well as the approximate load, are as follows:



	Auction Year
	2020	2021	2022	2023
36-Month Terms Ending	May 2023	May 2024	May 2025	May 2026	(A)
Load (MW)	2,800	2,900	2,800	2,800
$ per MWh	$102.16	$64.80	$76.30	$93.11

Auction Year
2014 2015 2016 2017
36-Month Terms Ending May 2017
May 2018
May 2019
May 2020
(A)
Load (MW) 2,800
2,900
2,800
2,800

$ per MWh $97.39 $99.54 $96.38 $90.78


~~(A)~~	(A)Prices set ~~in the 2017 BGS auction year became effective on June 1, 2017 when the 2014 BGS auction agreements expired.~~

~~Power seeks to mitigate volatility~~ in ~~its results by contracting in advance for~~ the sale of most of its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey electric distribution companies (EDCs) with a portion of their respective BGS requirements through the New Jersey2023 BGS auction ~~process, described above.~~became effective on June 1, 2023 when the 2020 BGS auction agreements expired.

PSE&G has a full-requirements contract with PSEG Power to meet the gas supply requirements of PSE&G’s gas customers. PSEG Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU

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permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. Current plans call for PSEG Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements. For additional information, see Note ~~18.~~19. Related-Party Transactions.

Pursuant to a process established by the BPU, New Jersey EDCs, including PSE&G, are required to purchase ZECs from eligible nuclear plants selected by the BPU. In April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were selected to receive ZEC revenue for approximately three years, through May 2022. In April 2021, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs for the three-year eligibility period starting June 2022. PSE&G has implemented a tariff to collect a non-bypassable distribution charge in the amount of $0.004 per KWh from its retail distribution customers to be used to purchase the ZECs from these plants. PSE&G will purchase the ZECs on a monthly basis with payment to be made annually following completion of each energy year. The legislation also requires nuclear plants to reapply for any subsequent three-year periods and allows the BPU to adjust prospective ZEC payments.

Minimum Fuel Purchase Requirements

PSEG Power’s nuclear fuel strategy is to maintain certain levels of uranium and to make periodic purchases to support such levels. As such, the commitments referred to in the following table may include estimated quantities to be purchased that deviate from contractual nominal quantities. PSEG Power’s minimum nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through ~~2020~~2026 and a significant portion through ~~2021~~2027 at Salem, Hope Creek and Peach Bottom. Additionally, available contractual volume flexibility provides for approximately 100% coverage of expected requirements through 2027.

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PSEG Power has various multi-year contracts for natural gas and firm ~~pipeline~~ transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess pipeline capacity available beyond the needs of PSE&G’s customers, Power can use the gas to make third-party sales and if excess volume remains after the third-party sales, supply its fossil generating stations in New Jersey.

~~Power also has various long-term fuel purchase commitments for coal through 2021 to support its Keystone and Conemaugh fossil generation stations.~~

As of ~~September~~June 30, ~~2017,~~2023, the total minimum purchase requirements included in these commitments were as follows:

Fuel Type Power's Share of Commitments through 2021
Millions
Nuclear Fuel
Uranium $ 257

Enrichment $ 328

Fabrication $ 178

Natural Gas $ 963

Coal $ 308



Fuel Type	PSEG Power’s Share of Commitments through 2027
	Millions
Nuclear Fuel
Uranium	$	379
Enrichment	$	309
Fabrication	$	183
Natural Gas	$	1,135

~~Regulatory Proceedings~~Pending FERC Matter

FERC ~~Compliance~~

~~PJM Bidding Matter~~

In the first quarter of 2014, Power discovered that it incorrectly calculated certain components of its cost-based bids for its New Jersey fossil generating units in the PJM energy market. Upon discovery of the errors, PSEG retained outside counsel to assist in the conduct of an investigation into the matter and self-reported the errors. As the internal investigation proceeded, additional pricing errors in the bids were identified. It was further determined that the quantity of energy that Power offered into the energy market for its fossil peaking units differed from the amount for which Power was compensated in the capacity market for those units. PSEG informed FERC, PJM and the PJM Independent Market Monitor (IMM) of these additional issues, corrected the identified errors, and modified the bid quantities for Power’s peaking units. Power has implemented procedures and continues to review its policies and practices to mitigate the risk of similar issues occurring in the future. During the three months ended March 31, 2014, based upon its best estimate available at the time, Power recorded a pre-tax charge to income in the amount of $25 million related to this matter.

~~Since September 2014, FERC Staff~~ has been conducting a non-public investigation of the Roseland-Pleasant Valley transmission project. In November 2021, FERC staff presented PSE&G with its non-public preliminary ~~non-public staff investigation into~~findings, alleging that PSE&G violated a FERC regulation. PSE&G disagrees with FERC staff’s allegations and believes it has factual and legal defenses that refute these ~~matters. While considerable uncertainty remains as~~allegations. PSE&G has the opportunity to ~~the final resolution of~~respond to these ~~matters, based upon developments in~~preliminary findings. The matter is pending and the investigation in the first quarter of 2017, Power believes the disgorgement and interest costs related to the cost-based bidding matter may range between approximately $35 million and $135 million, depending on the legal interpretation of the principles under the PJM Tariff, plus penalties. Since no point within this range is more likely than any other, Power has accrued the low end of this range of $35 million by recording an additional pre-tax charge to income of $10 million during the three months ended March 31, 2017. Powerongoing. PSE&G is unable to ~~reasonably~~predict the outcome or estimate the range of possible loss ~~if any, for~~related to this matter; however, depending on the ~~quantity~~success of ~~energy offered matter or~~PSE&G’s factual and legal arguments, the potential financial and other penalties that ~~FERC would impose relating to either the cost-based bidding or quantity of energy matter. However, any of these amounts~~PSE&G may incur could be ~~individually~~ material to ~~PSEG~~PSEG’s and ~~Power.~~PSE&G’s results of operations and financial condition.

~~Power continues to believe that it~~BPU Audit of PSE&G

In 2020, the BPU ordered the commencement of a comprehensive affiliate and management audit of PSE&G. It has ~~legal defenses that it may assert in~~been more than ten years since the BPU last conducted a ~~judicial challenge, including the legal defense that its cost-based bidding in a substantial majority~~management and affiliate audit of this kind of PSE&G, which is initiated periodically as required by New Jersey statutes/regulations. Phase 1 of the ~~hours was below~~audit reviews affiliate relations and cost allocation between PSE&G and its affiliates, including an analysis of the ~~allowed rate under~~relationship between PSE&G and PSEG Energy Resources & Trade, LLC, a wholly owned subsidiary of PSEG Power over the ~~Tariff~~past ten years, and ~~therefore any errors~~between PSE&G and PSEG LI. Phase 2 is a comprehensive management audit, which will address, among other things, executive management, corporate governance, system operations, human resources, cyber security, compliance with customer protection requirements and customer safety. The audit officially began in ~~those hours did~~late May 2021 and data collection (written discovery and interviews) has concluded. The BPU Audit Staff are in the process of finalizing their report. It is not ~~violate the Tariff or were immaterial. Furthermore, it is unclear whether the quantity of energy offered violated any legal requirement. As a result, PSEG and Power cannot~~possible at this time to predict the ~~final~~ outcome of ~~these matters.~~this matter.

~~Financial Transmission Rights (FTR) Auction Matter~~

In January 2017, ER&T received requests from the FERC Office of Enforcement relating to the planning and implementation of ER&T’s participation in PJM’s annual FTR auction for the 2016-2017 planning year and the monthly PJM FTR auctions for February, March and April 2016. In October 2017, FERC Staff closed the investigation with no impact to PSEG’s operations or future earnings results.

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Litigation

Sewaren 7 Construction

In June 2018, a complaint was filed in federal court in Newark, New Jersey against PSEG Fossil LLC, which at the time was a wholly owned subsidiary of PSEG Power, regarding an ongoing dispute with Durr Mechanical Construction, Inc. (Durr), a contractor on the Sewaren 7 project. Among other things, Durr seeks damages of $93 million and alleges that PSEG Power withheld money owed to Durr and that PSEG Power’s intentional conduct led to the inability of Durr to obtain prospective contracts. PSEG Power intends to vigorously defend against these allegations. In January 2021, the court partially granted PSEG Power’s motion to dismiss certain claims, reducing the amount claimed to $68 million. In December 2018, Durr filed for Chapter 11 bankruptcy in the federal court in the Southern District of New York (SDNY). The SDNY bankruptcy court has allowed the New Jersey litigation to proceed. PSEG Power has accrued an amount related to outstanding invoices which does not reflect an assessment of claims and potential counterclaims in this matter. Due to its preliminary nature, PSEG Power cannot predict the outcome of this matter.

Other Litigation and Legal Proceedings

PSEG and its subsidiaries are party to various lawsuits in the ordinary course of business. In view of the inherent difficulty in predicting the outcome of such matters, PSEG and PSE&G generally cannot predict the eventual outcome of the pending matters, the timing of the ultimate resolution of these matters, or the eventual loss, fines or penalties related to each pending matter.

In accordance with applicable accounting guidance, a liability is accrued when those matters present loss contingencies that are both probable and reasonably estimable. In such cases, there may be an exposure to loss in excess of any amounts accrued. PSEG will continue to monitor the matter for further developments that could affect the amount of the accrued liability that has been previously established.

Based on current knowledge, management does not believe that loss contingencies arising from pending matters, other than the matters described herein, could have a material adverse effect on PSEG’s or PSE&G’s consolidated financial position or liquidity. However, in light of the inherent uncertainties involved in these matters, some of which are beyond PSEG’s control, and the large or indeterminate damages sought in some of these matters, an adverse outcome in one or more of these matters could be material to PSEG’s or PSE&G’s results of operations or liquidity for any particular reporting period.

Note ~~10.~~11. Debt and Credit Facilities

Long-Term Debt Financing Transactions

The following long-term debt transactions occurred in the ~~nine~~six months ended ~~September~~June 30, ~~2017:~~

~~PSEG~~

entered into an agreement for a new term loan maturing June 2019. The term loan has a balance of $700 million at an interest rate of 1 month LIBOR + 0.80% and can be terminated at any time without penalty.2023:

PSE&G

•issued ~~$425~~$500 million of ~~3.00%~~4.65% Secured Medium-Term Notes (Green Bond), Series P, due March 2033,

•issued $400 million of 5.13% Secured Medium-Term Notes (Green Bond), Series P, due March 2053, and

•retired $500 million of 2.38% Secured Medium-Term Notes Series ~~L due May 2027.~~I, at maturity.

Short-Term Liquidity

PSEG meets its short-term liquidity requirements, as well as those of PSEG Power, primarily ~~with cash and~~ through the issuance of commercial ~~paper.~~paper and, from time to time, short-term loans. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facilities.

In March 2017, PSEG, Power and PSE&G amended their credit agreements, extending the expiration dates to March 2022. Concurrently, PSEG increased its existing $1 billion in credit facilities to $1.5 billion and Power decreased its existing $2.6 billion in credit facilities to $2.1 billion, which includes two new 3-year $100 million letter of credit facilities that expire in March 2020.

The commitments under the $4.2 billion credit facilities are provided by a diverse bank group. As of ~~September~~June 30, ~~2017,~~2023, the total available credit capacity was ~~$3.8~~$3.5 billion.

As of ~~September~~June 30, ~~2017,~~2023, no single institution represented more than 8%10% of the total commitments in the credit facilities.

As of ~~September~~June 30, ~~2017, total~~2023, PSEG’s liquidity position, including credit ~~capacity~~facilities and access to external financing, was ~~in excess of the total anticipated maximum liquidity~~expected to be sufficient to meet its projected stressed requirements ~~of PSEG, PSE&G and Power.~~over a 12-month planning horizon.

Each of the credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support its subsidiaries’ liquidity needs. ~~The total credit facilities and available liquidity as of September 30, 2017 were as follows:~~

As of September 30, 2017
Company/Facility
Total
Facility
Usage
Available
Liquidity

Expiration
Date
Primary Purpose
Millions
PSEG
  5-year Credit Facilities (A) $ 1,500
$ 215
$ 1,285
Mar 2022 Commercial Paper Support/Funding/Letters of Credit
Total PSEG $ 1,500
$ 215
$ 1,285

PSE&G
5-year Credit Facility (A) $ 600
$ 15
$ 585
Mar 2022 Commercial Paper Support/Funding/Letters of Credit
Total PSE&G $ 600
$ 15
$ 585

Power
  3-year LC Facilities $ 200
$ 112
$ 88
Mar 2020 Letters of Credit
  5-year Credit Facilities 1,900
70
1,830
Mar 2022 Funding/Letters of Credit
Total Power $ 2,100
$ 182
$ 1,918

Total $ 4,200
$ 412
$ 3,788


~~(A)~~	The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs, under which as of September 30, 2017, PSEG had $202 million outstanding at a weighted average interest rate of 1.37%. PSE&G had no amounts outstanding under its Commercial Paper Program as of September 30, 2017.

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The total committed credit facilities and available liquidity as of June 30, 2023 were as follows:



	As of June 30, 2023
Company/Facility	Total Facility		Usage (B)		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
Revolving Credit Facility (A)	$	1,500	$	152	$	1,348	Mar 2027	Commercial Paper Support/Funding/Letters of Credit
Total PSEG	$	1,500	$	152	$	1,348
PSE&G
Revolving Credit Facility	$	1,000	$	318	$	682	Mar 2027	Commercial Paper Support/Funding/Letters of Credit
Total PSE&G	$	1,000	$	318	$	682
PSEG Power
Revolving Credit Facility (A)	$	1,250	$	39	$	1,211	Mar 2027	Funding/Letters of Credit
Letter of Credit Facility	100		—		100		Apr 2025	Letters of Credit
Letter of Credit Facility	200		86		114		Sept 2024	Letters of Credit
Letter of Credit Facility	100		66		34		Apr 2024	Letters of Credit
Total PSEG Power	$	1,650	$	191	$	1,459
Total (C)	$	4,150	$	661	$	3,489

(A)Master Credit Facility with sub-limits of $1.5 billion for PSEG and $1.25 billion for PSEG Power; sub-limits can be adjusted pursuant to the terms of the Master Credit Facility agreement. The PSEG sub-limit includes a sustainability linked pricing based mechanism with potential increases or decreases, which are not expected to be material, depending on performance relative to targeted methane emission reductions.

(B)The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs, under which as of June 30, 2023, PSEG had $149 million outstanding at a weighted average interest rate of 5.53% and PSE&G had $298 million outstanding at a weighted average interest rate of 5.49%.

(C)Amounts do not include uncommitted credit facilities or 364-day term loans.

A subsidiary of PSEG Power has an uncommitted credit facility for $150 million, which can be drawn to fund its cash collateral postings. As of June 30, 2023, there were no amounts outstanding under this facility.

Net Cash Collateral Postings

During the second half of 2021 and continuing into 2023, forward energy prices have demonstrated considerable price volatility. This has led to significant variations in PSEG Power’s collateral requirements. As of June 30, 2023, net cash collateral postings were approximately $426 million. While currently off their highs experienced during 2022, collateral postings could remain volatile in the future.

Short-Term Loans

PSEG

In January 2023, PSEG repaid $750 million of the $1.5 billion 364-day variable rate term loan that was issued in April 2022 and in April 2023 the remaining $750 million matured. In April 2023, PSEG entered into a new 364-day variable rate term loan agreement for $750 million. In May 2023, PSEG’s $500 million 364-day variable rate term loan matured.

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Note ~~11.~~12. Financial Risk Management Activities

Derivative accounting guidance requires that a derivative instrument be recognized as either an asset or a liability at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation provided that the derivative instrument meets specific, restrictive criteria, both at the time of designation and on an ongoing basis. These alternative permissible treatments include normal purchases and normal sales (NPNS), cash flow hedge and fair value hedge accounting. PSEG ~~Power~~ and PSE&G have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements and fuel agreements. PSEG uses interest rate swaps and other derivatives, which are designated and ~~effective~~qualifying as cash flow or fair value hedges. PSEG Power ~~and PSE&G enter~~enters into additional contracts that are derivatives, but are not designated as either cash flow hedges or fair value hedges. These transactions are economic hedges and are recorded at fair market ~~value.~~value with changes recognized in earnings.

Commodity Prices

Within PSEG and its affiliate companies, PSEG Power has the most exposure to commodity price risk. PSEG Power is exposed to commodity price risk primarily relating ~~primarily~~ to changes in the market price of electricity, ~~fossil fuels~~natural gas and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. PSEG Power uses a variety of derivative and non-derivative instruments, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of PSEG Power’s expected generation. PSEG Power also uses derivatives to hedge a portion of its anticipated BGSS obligations with PSE&G. For additional information see Note 10. Commitments and Contingent Liabilities. Changes in the fair market value of ~~the~~these derivative contracts are recorded in earnings.

Interest Rates

PSEG, ~~Power~~PSE&G and ~~PSE&G~~PSEG Power are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. ~~In addition, they have used~~PSEG, PSE&G and PSEG Power may use a mix of fixed and floating rate debt, interest rate swaps and interest rate ~~swaps.~~

~~Fair Value Hedges~~

PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. The changes in fair value of the interest rate swaps are fully offset by changes in the fair value of the underlying forecasted interest payments of the debt. There were no outstanding interest rate swaps as of September 30, 2017 or December 31, 2016. The fair value hedges reduced interest expense by $2 million and $6 million for the three months and nine months ended September 30, 2016.lock agreements.

Cash Flow Hedges

PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related ~~primarily~~ to variable-rate debt instruments. AsThe fair value of ~~September~~these hedges were $13 million and $1 million as of June 30, ~~2017~~2023 and December 31, ~~2016,~~2022, respectively. As of June 30, 2023, PSEG had interest rate hedges outstanding totaling ~~$500~~$900 million. ~~These hedges~~PSEG executed these interest rate swaps to convert ~~PSEG’s $500 million~~a portion of PSEG Power’s $1.25 billion variable rate term loan due ~~November 2017~~March 2025 into a fixed rate ~~loan~~. ~~As of December 31, 2016, the fair value of these hedges was $1 million and was immaterial as of September 30, 2017. There was no ineffectiveness as of September 30, 2017 and December 31, 2016.~~loans.

The Accumulated Other Comprehensive Income (Loss) (after tax) related to ~~existing~~outstanding and terminated interest rate derivatives designated as cash flow hedges was $1$7 million and $2$(3) million as of ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016,~~2022, respectively. The after-tax unrealized ~~gain~~gains on these hedges expected to be reclassified to earnings during the next 12 months ~~is immaterial.~~are $5 million.

Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the Condensed Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with PSEG’s accounting policy, these positions are offset on the Condensed Consolidated Balance Sheets of ~~Power~~PSEG. For additional information see Note 13. Fair Value Measurements.

Substantially all derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and ~~PSEG.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table~~did not have any collateral posted or received as of ~~Contents~~

June 30, 2023 and December 31, 2022. The following tabular disclosure does not include the offsetting of trade receivables and payables.

As of September 30, 2017
Power (A) PSEG (A) Consolidated
Not Designated Designated as Hedges
Balance Sheet Location
Energy-
Related
Contracts

Netting
(B)

Total
Power

Interest
Rate
Swaps

Total
Derivatives

Millions
Derivative Contracts
Current Assets $ 352
$ (268 ) $ 84
$ —
$ 84

Noncurrent Assets 178
(116 ) 62
—
62

Total Mark-to-Market Derivative Assets $ 530
$ (384 ) $ 146
$ —
$ 146

Derivative Contracts
Current Liabilities $ (268 ) $ 261
$ (7 ) $ —
$ (7 )
Noncurrent Liabilities (110 ) 109
(1 ) —
(1 )
Total Mark-to-Market Derivative (Liabilities) $ (378 ) $ 370
$ (8 ) $ —
$ (8 )
Total Net Mark-to-Market Derivative Assets (Liabilities) $ 152
$ (14 ) $ 138
$ —
$ 138

As of December 31, 2016
Power (A) PSE&G (A) PSEG (A) Consolidated
Not Designated Not Designated Designated as Hedges
Balance Sheet Location
Energy-
Related
Contracts

Netting
(B)

Total
Power

Energy-
Related
Contracts

Interest
Rate
Swaps

Total
Derivatives

Millions
Derivative Contracts
Current Assets $ 435
$ (273 ) $ 162
$ —
$ 1
$ 163

Noncurrent Assets 122
(98 ) 24
—
—
24

Total Mark-to-Market Derivative Assets $ 557
$ (371 ) $ 186
$ —
$ 1
$ 187

Derivative Contracts
Current Liabilities $ (285 ) $ 277
$ (8 ) $ (5 ) $ —
$ (13 )
Noncurrent Liabilities (98 ) 95
(3 ) —
—
(3 )
Total Mark-to-Market Derivative (Liabilities) $ (383 ) $ 372
$ (11 ) $ (5 ) $ —
$ (16 )
Total Net Mark-to-Market Derivative Assets (Liabilities) $ 174
$ 1
$ 175
$ (5 ) $ 1
$ 171

40


~~(A)~~	Substantially all of Power’s and PSEG’s derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of September 30, 2017 and December 31, 2016. PSE&G does not have any derivative contracts subject to master netting or similar agreements.

~~(B)~~

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents



	As of June 30, 2023
	PSEG		PSEG Power						Consolidated
	Cash Flow Hedges		Not Designated
Balance Sheet Location	Interest Rate Swaps		Energy- Related Contracts		Netting (A)		Total PSEG Power		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	11	$	767	$	(687)	$	80	$	91
Noncurrent Assets	2		633		(573)		60		62
Total Mark-to-Market Derivative Assets	$	13	$	1,400	$	(1,260)	$	140	$	153
Derivative Contracts
Current Liabilities	$	—	$	(919)	$	853	$	(66)	$	(66)
Noncurrent Liabilities	—		(698)		690		(8)		(8)
Total Mark-to-Market Derivative (Liabilities)	$	—	$	(1,617)	$	1,543	$	(74)	$	(74)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	13	$	(217)	$	283	$	66	$	79

~~positions.~~



	As of December 31, 2022
	PSEG		PSEG Power						Consolidated
	Cash Flow Hedges		Not Designated
Balance Sheet Location	Interest Rate Swaps		Energy- Related Contracts		Netting (A)		Total PSEG Power		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	4	$	1,721	$	(1,707)	$	14	$	18
Noncurrent Assets	—		629		(614)		15		15
Total Mark-to-Market Derivative Assets	$	4	$	2,350	$	(2,321)	$	29	$	33
Derivative Contracts
Current Liabilities	$	—	$	(2,447)	$	2,323	$	(124)	$	(124)
Noncurrent Liabilities	(3)		(1,139)		1,109		(30)		(33)
Total Mark-to-Market Derivative (Liabilities)	$	(3)	$	(3,586)	$	3,432	$	(154)	$	(157)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	1	$	(1,236)	$	1,111	$	(125)	$	(124)

(A) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral (received) posted that has been allocated to derivative positions, where the right of offset exists, has been offset on the Condensed Consolidated Balance Sheets. As of June 30, 2023 and December 31, 2022, PSEG Power had net cash collateral (receipts) payments to counterparties of $426 million and $1,521 million, respectively. Of ~~the $(14)~~these net cash collateral (receipts) payments, $283 million and $1,111 million as of ~~September~~June 30, ~~2017, $(7) million was netted against current assets,~~2023 and ~~$(7) million was netted against noncurrent assets. As of~~ December 31, ~~2016, net cash collateral (received) paid of $1 million was~~2022, respectively, were netted against the corresponding net derivative contract positions. Of the $1$283 million as of June 30, 2023, $(5) million was netted against current assets, $(1) million against noncurrent assets, $171 million against current liabilities and $118 million against noncurrent liabilities. Of the $1,111 million as of December 31, ~~2016, $(3) million was netted against noncurrent assets, and $4~~2022, $616 million was netted against current liabilities and $495 million against noncurrent liabilities.

Certain of PSEG Power’s derivative instruments contain provisions that require PSEG Power to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PSEG Power’s credit rating from each of

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if PSEG Power were to be downgraded to a below investment grade rating by S&P or Moody’s, it would be required to provide additional collateral. A below investment grade credit rating for PSEG Power would represent a ~~three~~two level downgrade from its current Moody’s and S&P ~~or Moody’s~~ ratings. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. PSEG Power also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margin requirements.

The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the NYMEX and ICE that are fully collateralized) was ~~$16 million and $19~~$76 million as of ~~September~~June 30, ~~2017~~2023 and $190 million as of December 31, 2022. As of June 30, 2023 and December 31, ~~2016, respectively. As of each of September 30, 2017 and December 31, 2016,~~2022, PSEG Power had the contractual right of offset of $9$5 million and $41 million, respectively, related to derivative instruments that are assets with the same counterparty under master agreements and net of margin posted. If PSEG Power had been downgraded to a below investment grade rating, it would have had additional collateral obligations of $7$71 million and ~~$10~~$149 million as of ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016,~~2022, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral.

The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive ~~Income (AOCI)~~Loss (AOCL) of derivative instruments designated as cash flow hedges for the three months and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016.~~

Derivatives in Cash Flow
Hedging Relationships

Amount of Pre-Tax
Gain (Loss)
Recognized in AOCI on Derivatives
(Effective Portion)

Location of
Pre-Tax Gain (Loss) Reclassified from AOCI into Income

Amount of Pre-Tax
Gain (Loss)
Reclassified from AOCI into Income
(Effective Portion)

Three Months Ended Three Months Ended
September 30, September 30,
2017 2016 2017 2016
Millions Millions
PSEG
Interest Rate Swaps $ 1
$ 1
Interest Expense $ 2
$ —

Total PSEG $ 1
$ 1
$ 2
$ —

2022:

Derivatives in Cash Flow
Hedging Relationships

Amount of Pre-Tax
Gain (Loss)
Recognized in AOCI on Derivatives
(Effective Portion)

Location of
Pre-Tax Gain (Loss) Reclassified from AOCI into Income

Amount of Pre-Tax
Gain (Loss)
Reclassified from AOCI into Income
(Effective Portion)

Nine Months Ended Nine Months Ended
September 30, September 30,
2017 2016 2017 2016
Millions Millions
PSEG
Interest Rate Swaps $ 1
$ 3
Interest Expense $ 2
$ —

Total PSEG $ 1
$ 3
$ 2
$ —



Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCL on Derivatives				Location of Pre-Tax Gain (Loss) Reclassified from AOCL into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCL into Income
	Three Months Ended					Three Months Ended
	June 30,					June 30,
	2023		2022			2023		2022
	Millions					Millions
PSEG

Interest Rate Swaps	$	17	$	—	Interest Expense	$	1	$	(1)
Total PSEG	$	17	$	—		$	1	$	(1)



Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCL on Derivatives				Location of Pre-Tax Gain (Loss) Reclassified from AOCL into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCL into Income
	Six Months Ended					Six Months Ended
	June 30,					June 30,
	2023		2022			2023		2022
	Millions					Millions
PSEG

Interest Rate Swaps	$	14	$	—	Interest Expense	$	—	$	(2)
Total PSEG	$	14	$	—		$	—	$	(2)

The effect of interest rate cash flow hedges is recorded in Interest Expense in PSEG’s Condensed Consolidated Statement of Operations. For the six months ended June 30, 2023 and 2022, the amount of loss on interest rate hedges reclassified from Accumulated Other Comprehensive Loss into income was less than $1 million and $(1) million after-tax, respectively.

The following reconciles the Accumulated Other Comprehensive Income (Loss) for derivative activity included in AOCL of PSEG on a pre-tax and after-tax basis.

~~There were no pre-tax gains (losses) recognized in income on derivatives (ineffective portion) as of September 30, 2017 and~~

~~2016.~~

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents



Accumulated Other Comprehensive Income (Loss)	Pre-Tax		After-Tax
	Millions



Balance as of December 31, 2021	$	(9)	$	(6)
Loss Recognized in AOCL	—		—
Less: Loss Reclassified into Income	5		3
Balance as of December 31, 2022	$	(4)	$	(3)
Gain Recognized in AOCL	14		10
Less: Loss Reclassified into Income	—		—
Balance as of June 30, 2023	$	10	$	7

~~The following reconciles the AOCI for derivative activity included in the Accumulated Other Comprehensive Loss of PSEG on a pre-tax and after-tax basis.~~

Accumulated Other Comprehensive Income Pre-Tax After-Tax
Millions
Balance as of December 31, 2015 $ —
$ —

Gain Recognized in AOCI 3
2

Less: Gain Reclassified into Income —
—

Balance as of December 31, 2016 $ 3
$ 2

Gain Recognized in AOCI 1
—

Less: Gain Reclassified into Income (2 ) (1 )
Balance as of September 30, 2017 $ 2
$ 1

The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the three months and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016.~~2022, respectively. PSEG Power’s derivative contracts reflected in this table include contracts to hedge the purchase and sale of electricity and natural gas, and the purchase of fuel. The table does not include contracts for which Power has designated as NPNS, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load.

Derivatives Not Designated as Hedges
Location of Pre-Tax
Gain (Loss)
Recognized in Income
on Derivatives
Pre-Tax Gain (Loss) Recognized in Income on Derivatives
Three Months Ended Nine Months Ended
September 30, September 30,
2017 2016 2017 2016
Millions
PSEG and Power
Energy-Related Contracts Operating Revenues $ 25
$ 125
$ 221
$ 255

Energy-Related Contracts Energy Costs (3 ) (11 ) (19 ) (3 )
Total PSEG and Power $ 22
$ 114
$ 202
$ 252



Derivatives Not Designated as Hedges	Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives	Pre-Tax Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2023		2022		2023		2022
		Millions				Millions
Energy-Related Contracts	Operating Revenues	$	339	$	(354)	$	1,241	$	(1,398)
Energy-Related Contracts	Energy Costs	(1)		(1)		—		(1)
Total		$	338	$	(355)	$	1,241	$	(1,399)

The following ~~reflects~~table summarizes the ~~gross~~net notional volume ~~on an absolute value basis,~~purchases/(sales) of ~~derivatives~~open derivative transactions by commodity as of ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016.~~2022.

Type Notional Total PSEG Power PSE&G
Millions
As of September 30, 2017
Natural Gas Dekatherm (Dth) 265
—
265
—

Electricity MWh 332
—
332
—

Financial Transmission Rights (FTRs) MWh 5
—
5
—

Interest Rate Swaps U.S. Dollars 500
500
—
—

As of December 31, 2016
Natural Gas Dth 357
—
348
9

Electricity MWh 323
—
323
—

FTRs MWh 9
—
9
—

Interest Rate Swaps U.S. Dollars 500
500
—
—

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

As of

Type

Notional

June 30, 2023

December 31, 2022

Millions

Natural Gas

Dekatherm (Dth)

Electricity

MWh

(63)

(60)

Financial Transmission Rights (FTRs)

MWh

Interest Rate Swaps

U.S. Dollars

900

1,050

Credit Risk

Credit risk relates to the risk of loss that PSEG Power would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG has established credit policies that it believes significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on ~~Power’s and~~ PSEG’s financial condition, results of operations or net cash flows.

As of ~~September~~June 30, ~~2017, 99%~~2023, nearly 100% of the net credit exposure for PSEG Power’s wholesale operations was with investment grade counterparties. ~~Credit~~There were two counterparties with credit exposure greater than 10% of the total. These credit exposures were with PSE&G and one non-affiliated counterparty. The PSE&G credit exposure is ~~defined as any positive results~~eliminated in consolidation. See Note 19. Related-Party Transactions for additional information.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of ~~netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives, NPNS and non-derivatives).~~Contents

The following table provides information on Power’s credit risk from others, net of collateral, as of September 30, 2017. It further delineates that exposure by the credit rating of the counterparties, which is determined by the lowest rating from S&P, Moody’s or an internal scoring model. In addition, it provides guidance on the concentration of credit risk to individual counterparties and an indication of the quality of Power’s credit risk by credit rating of the counterparties.

Rating
Current
Exposure
Collateral Held
Net
Exposure

Number of
Counterparties
>10%

Net Exposure of
Counterparties
>10%

Millions Millions
Investment Grade $ 318
$ 55
$ 263
2
$ 128
(A)
Non-Investment Grade 5
1
4
—
—

Total $ 323
$ 56
$ 267
2
$ 128


~~(A)~~	~~Includes net exposure of $97 million with PSE&G.~~

~~As of September 30, 2017, collateral held from counterparties where Power had credit exposure included $3 million in cash collateral and $53 million in letters of credit.~~

~~As of~~ ~~September 30, 2017, Power had~~ ~~144~~ ~~active counterparties.~~

PSE&G’s supplier master agreements are approved by the BPU and govern the terms of its electric supply procurement contracts. These agreements define a supplier’s performance assurance requirements and allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s credit ratings from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day the procurement transaction is executed, compared to the forward price curve for energy on the valuation day. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post a parental ~~guaranty~~guarantee or other security instrument such as a letter of credit or cash, as collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of ~~September~~June 30, ~~2017, primarily all~~2023, PSEG held parental guarantees, letters of ~~the posted collateral was in the form of parental guarantees. The unsecured~~ credit ~~used by the suppliers represents PSE&G’s net credit exposure.~~and cash as security. PSE&G’s BGS suppliers’ credit exposure is calculated each business day. As of ~~September~~June 30, ~~2017,~~2023, PSE&G had no ~~net~~unsecured mark-to-market credit exposure with ~~suppliers, including Power.~~its suppliers.

PSE&G is permitted to recover its costs of procuring energy through the BPU-approved BGS tariffs. PSE&G’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

Note ~~12.~~13. Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance for fair value measurement emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:

Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG and PSE&G ~~and Power~~ have the ability to access. These consist primarily of listed equity securities and money market mutual funds, as well as natural gas futures contracts executed on NYMEX.

Level 2—measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities.

Level 3—measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entity’s own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. ~~As of September 30, 2017, these consisted~~These consist primarily of certain electric load ~~contracts and gas~~ contracts.

Certain derivative transactions may transfer from Level 2 to Level 3 if inputs become unobservable and internal modeling techniques are employed to determine fair value. Conversely, measurements may transfer from Level 3 to Level 2 if the inputs become observable.

The following tables present information about PSEG’s and PSE&G’s ~~and Power’s~~ respective assets and (liabilities) measured at fair value on a recurring basis as of ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016,~~2022, including the fair value measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for PSE~~&G and Power.~~&G.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents



	Recurring Fair Value Measurements as of June 30, 2023
Description	Total		Netting (E)		Quoted Market Prices for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	480	$	—	$	480	$	—	$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	140	$	(1,260)	$	5	$	1,395	$	—
Interest Rate Swaps (C)	$	13	$	—	$	—	$	13	$	—
NDT Fund (D)
Equity Securities	$	1,189	$	—	$	1,189	$	—	$	—
Debt Securities—U.S. Treasury	$	277	$	—	$	—	$	277	$	—
Debt Securities—Govt Other	$	384	$	—	$	—	$	384	$	—
Debt Securities—Corporate	$	531	$	—	$	—	$	531	$	—

Rabbi Trust (D)
Equity Securities	$	21	$	—	$	21	$	—	$	—
Debt Securities—U.S. Treasury	$	59	$	—	$	—	$	59	$	—
Debt Securities—Govt Other	$	33	$	—	$	—	$	33	$	—
Debt Securities—Corporate	$	72	$	—	$	—	$	72	$	—

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(74)	$	1,543	$	(1)	$	(1,612)	$	(4)

PSE&G
Assets:
Cash Equivalents (A)	$	100	$	—	$	100	$	—	$	—


Rabbi Trust (D)
Equity Securities	$	4	$	—	$	4	$	—	$	—
Debt Securities—U.S. Treasury	$	11	$	—	$	—	$	11	$	—
Debt Securities—Govt Other	$	6	$	—	$	—	$	6	$	—
Debt Securities—Corporate	$	12	$	—	$	—	$	12	$	—

Recurring Fair Value Measurements as of September 30, 2017
Description Total

Netting (E)

Quoted Market Prices for Identical Assets
(Level 1)
Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3)
Millions
PSEG
Assets:
Cash Equivalents (A) $ 220
$ —
$ 220
$ —
$ —

Derivative Contracts:
Energy-Related Contracts (B) $ 146
$ (384 ) $ 11
$ 513
$ 6

NDT Fund (D)
Equity Securities $ 1,032
$ —
$ 1,030
$ 2
$ —

Debt Securities—U.S. Treasury $ 249
$ —
$ —
$ 249
$ —

Debt Securities—Govt Other $ 318
$ —
$ —
$ 318
$ —

Debt Securities—Corporate $ 358
$ —
$ —
$ 358
$ —

Other Securities $ 55
$ —
$ 55
$ —
$ —

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 23
$ —
$ 23
$ —
$ —

Debt Securities—U.S. Treasury $ 51
$ —
$ —
$ 51
$ —

Debt Securities—Govt Other $ 33
$ —
$ —
$ 33
$ —

Debt Securities—Corporate $ 120
$ —
$ —
$ 120
$ —

Other Securities $ 2
$ —
$ 2
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (8 ) $ 370
$ (6 ) $ (372 ) $ —

PSE&G
Assets:
Cash Equivalents (A) $ 220
$ —
$ 220
$ —
$ —

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 5
$ —
$ 5
$ —
$ —

Debt Securities—U.S. Treasury $ 10
$ —
$ —
$ 10
$ —

Debt Securities—Govt Other $ 7
$ —
$ —
$ 7
$ —

Debt Securities—Corporate $ 24
$ —
$ —
$ 24
$ —

Other Securities $ —
$ —
$ —
$ —
$ —

Power

Assets:
Derivative Contracts:
Energy-Related Contracts (B) $ 146
$ (384 ) $ 11
$ 513
$ 6

NDT Fund (D)
Equity Securities $ 1,032
$ —
$ 1,030
$ 2
$ —

Debt Securities—U.S. Treasury $ 249
$ —
$ —
$ 249
$ —

Debt Securities—Govt Other $ 318
$ —
$ —
$ 318
$ —

Debt Securities—Corporate $ 358
$ —
$ —
$ 358
$ —

Other Securities $ 55
$ —
$ 55
$ —
$ —

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 6
$ —
$ 6
$ —
$ —

Debt Securities—U.S. Treasury $ 13
$ —
$ —
$ 13
$ —

Debt Securities—Govt Other $ 8
$ —
$ —
$ 8
$ —

Debt Securities—Corporate $ 30
$ —
$ —
$ 30
$ —

Other Securities $ —
$ —
$ —
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (8 ) $ 370
$ (6 ) $ (372 ) $ —

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents



	Recurring Fair Value Measurements as of December 31, 2022
Description	Total		Netting (E)		Quoted Market Prices for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	385	$	—	$	385	$	—	$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	29	$	(2,321)	$	42	$	2,307	$	1
Interest Rate Swaps (C)	$	4	$	—	$	—	$	4	$	—
NDT Fund (D)
Equity Securities	$	1,072	$	—	$	1,072	$	—	$	—
Debt Securities—U.S. Treasury	$	288	$	—	$	—	$	288	$	—
Debt Securities—Govt Other	$	339	$	—	$	—	$	339	$	—
Debt Securities—Corporate	$	529	$	—	$	—	$	529	$	—

Rabbi Trust (D)
Equity Securities	$	20	$	—	$	20	$	—	$	—
Debt Securities—U.S. Treasury	$	57	$	—	$	—	$	57	$	—
Debt Securities—Govt Other	$	32	$	—	$	—	$	32	$	—
Debt Securities—Corporate	$	74	$	—	$	—	$	74	$	—

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(154)	$	3,432	$	(3)	$	(3,537)	$	(46)
Interest Rate Swaps (C)	$	(3)	$	—	$	—	$	(3)	$	—
PSE&G
Assets:
Cash Equivalents (A)	$	165	$	—	$	165	$	—	$	—
Rabbi Trust (D)
Equity Securities	$	3	$	—	$	3	$	—	$	—
Debt Securities—U.S. Treasury	$	10	$	—	$	—	$	10	$	—
Debt Securities—Govt Other	$	6	$	—	$	—	$	6	$	—
Debt Securities—Corporate	$	13	$	—	$	—	$	13	$	—

(A)Represents money market mutual funds.

Recurring Fair Value Measurements as of December 31, 2016
Description Total Netting (E)
Quoted Market Prices for Identical Assets
(Level 1)
Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3)
Millions
PSEG
Assets:
Cash Equivalents (A) $ 365
$ —
$ 365
$ —
$ —

Derivative Contracts:
Energy-Related Contracts (B) $ 186
$ (371 ) $ 17
$ 533
$ 7

Interest Rate Swaps (C) $ 1
$ —
$ —
$ 1
$ —

NDT Fund (D)
Equity Securities $ 957
$ —
$ 954
$ 3
$ —

Debt Securities—U.S. Treasury $ 227
$ —
$ —
$ 227
$ —

Debt Securities—Govt Other $ 293
$ —
$ —
$ 293
$ —

Debt Securities—Corporate $ 337
$ —
$ —
$ 337
$ —

Other Securities $ 44
$ —
$ 44
$ —
$ —

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 22
$ —
$ 22
$ —
$ —

Debt Securities—U.S. Treasury $ 37
$ —
$ —
$ 37
$ —

Debt Securities—Govt Other $ 66
$ —
$ —
$ 66
$ —

Debt Securities—Corporate $ 91
$ —
$ —
$ 91
$ —

Other Securities $ 1
$ —
$ 1
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (16 ) $ 372
$ (18 ) $ (364 ) $ (6 )
PSE&G
Assets:
Cash Equivalents (A) $ 365
$ —
$ 365
$ —
$ —

Derivative Contracts:
Energy Related Contracts (B) $ —
$ —
$ —
$ —
$ —

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 5
$ —
$ 5
$ —
$ —

Debt Securities—U.S. Treasury $ 7
$ —
$ —
$ 7
$ —

Debt Securities—Govt Other $ 13
$ —
$ —
$ 13
$ —

Debt Securities—Corporate $ 18
$ —
$ —
$ 18
$ —

Other Securities $ —
$ —
$ —
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (5 ) $ —
$ —
$ —
$ (5 )
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B) $ 186
$ (371 ) $ 17
$ 533
$ 7

NDT Fund (D)
Equity Securities $ 957
$ —
$ 954
$ 3
$ —

Debt Securities—U.S. Treasury $ 227
$ —
$ —
$ 227
$ —

Debt Securities—Govt Other $ 293
$ —
$ —
$ 293
$ —

Debt Securities—Corporate $ 337
$ —
$ —
$ 337
$ —

Other Securities $ 44
$ —
$ 44
$ —
$ —

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 5
$ —
$ 5
$ —
$ —

Debt Securities—U.S. Treasury $ 9
$ —
$ —
$ 9
$ —

Debt Securities—Govt Other $ 16
$ —
$ —
$ 16
$ —

Debt Securities—Corporate $ 23
$ —
$ —
$ 23
$ —

Other Securities $ —
$ —
$ —
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (11 ) $ 372
$ (18 ) $ (364 ) $ (1 )

(B)Level 1—These contracts represent natural gas futures contracts executed on NYMEX, and are being valued solely on settled pricing inputs which come directly from the exchange.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~


~~(A)~~	~~Represents money market mutual funds.~~


~~(B)~~	Level 1— During 2016 a net fair value of $1 million relating to energy-related contracts was transferred from Level 2 into Level 1. These contracts represent natural gas futures contracts executed on NYMEX, and are being valued solely on settled pricing inputs which come directly from the exchange.

Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using settled prices from similar assets and liabilities from an exchange, such as NYMEX, ICE and Nodal Exchange, or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.

Level 3—Unobservable inputs are used for the valuation of certain contracts. See “Additional Information Regarding Level 3 Measurements” below for more information on the utilization of unobservable inputs.


~~(C)~~	Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.

~~(D)~~

The fair value measurement tables exclude an immaterial amount of cash as of September 30, 2017 and $1 million as of December 31, 2016, which is part of the NDT Fund. The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in a Russell 3000 index fund and various fixed income securities classified as “available for sale” as of September 30, 2017. The Rabbi Trust maintained investments in a S&P 500 index fund and various securities classified as “available for sale” as of December 31, 2016. These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).

(C)Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgement.

(D)The fair value measurement table excludes cash and foreign currency of $2 million in the NDT Fund as of June 30, 2023 and December 31, 2022. The NDT Fund maintains investments in various equity and fixed income securities. The Rabbi Trust maintains investments in a Russell 3000 index fund and various fixed income securities. These

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).

Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain ~~open-ended mutual~~other equity securities in the NDT and Rabbi Trust Funds consist primarily of investments in money market funds which seek a high level of current income as is consistent with ~~mainly~~the preservation of capital and the maintenance of liquidity. To pursue its goals, the funds normally invest in diversified portfolios of high quality, short-term, ~~investments are valued based on unadjusted quoted prices in active markets.~~dollar-denominated debt securities and government securities. The funds’ net asset value is priced and published daily. The Rabbi ~~Trust equity~~Trust’s Russell 3000 index fund is valued based on quoted prices in an active ~~market.~~market and can be redeemed daily without restriction.

Level 2—NDT and Rabbi Trust fixed income securities include ~~primarily~~ investment grade corporate bonds, collateralized mortgage obligations, ~~asset backed~~asset-backed securities and certain government and U.S. Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. ~~The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology.~~ Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield.

~~(E)~~

Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Condensed Consolidated Balance Sheets. As of September 30, 2017, net cash collateral (received) paid of $(14) million was netted against the corresponding net derivative contract positions. The $(14) million of cash collateral as of September 30, 2017 was netted against assets. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million of cash collateral as of December 31, 2016, $(3) million was netted against assets, and $4 million was netted against liabilities.

(E)Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. See Note 12. Financial Risk Management Activities for additional detail.

Additional Information Regarding Level 3 Measurements

For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee (RMC) approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The RMC reports to the Corporate Governance and Audit Committees of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group and used for financial reporting purposes. PSEG considers credit and ~~nonperformance~~non-performance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and ~~nonperformance~~non-performance risk by counterparty. The impacts of credit and ~~nonperformance~~non-performance risk were not material to the financial statements.

For PSE&G, the natural gas supply contract was measured at fair value using modeling techniques taking into account the current price of natural gas adjusted for appropriate risk factors, as applicable, and internal assumptions about transportation costs, and accordingly, the fair value measurements are classified in Level 3. The fair value of Power’s electric load contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. The following tables provide details surrounding significant Level 3 valuations as of September 30, 2017 and December 31, 2016.

Quantitative Information About Level 3 Fair Value Measurements

Significant
Fair Value as of Valuation Unobservable
Commodity Level 3 Position September 30, 2017 Technique(s) Input Range
Assets (Liabilities)
Millions
Power
Electricity Electric Load Contracts $ 5
$ —
Discounted Cash flow Historic Load Variability 0% to +10%
Gas Other 1
—

Total Power $ 6
$ —

Total PSEG $ 6
$ —

Quantitative Information About Level 3 Fair Value Measurements

Significant
Fair Value as of Valuation Unobservable
Commodity Level 3 Position December 31, 2016 Technique(s) Input Range
Assets (Liabilities)
Millions
PSE&G
Gas Natural Gas Supply Contract $ —
$ (5 ) Discounted Cash Flow Transportation Costs $0.60 to $0.80/Dth
Total PSE&G $ —
$ (5 )
Power
Electricity Electric Load Contracts $ 7
$ (1 ) Discounted Cash Flow Historic Load Variability 0% to +10%
Gas (A) Other —
—

Total Power $ 7
$ (1 )
Total PSEG $ 7
$ (6 )


~~(A)~~	~~Includes gas positions which were immaterial.~~

Significant unobservable inputs listed above would have a direct impact on the fair values of the above Level 3 instruments if they were adjusted. For energy-related contracts in cases where Power is a seller, an increase in the load variability would decrease the fair value.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

~~A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the three months ended~~ ~~September 30, 2017~~ ~~and September 30, 2016, respectively, follows:~~

~~Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Three Months and Nine Months Ended September 30, 2017~~

Three Months Ended September 30, 2017

Total Gains or (Losses)
Realized/Unrealized

Description Balance as of July 1, 2017
Included in
Income (A)

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

Transfers
In/Out (D)
Balance as of September 30, 2017
Millions
PSEG
Net Derivative Assets (Liabilities) $ 6
$ 3
$ —
$ —
$ (3 ) $ —
$ 6

PSE&G
Net Derivative Assets (Liabilities) $ —
$ —
$ —
$ —
$ —
$ —
$ —

Power
Net Derivative Assets (Liabilities) $ 6
$ 3
$ —
$ —
$ (3 ) $ —
$ 6

Nine Months Ended September 30, 2017

Total Gains or (Losses)
Realized/Unrealized

Description Balance as of January 1, 2017
Included in
Income (A)

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

Transfers
In/Out (D)
Balance as of September 30, 2017
Millions
PSEG
Net Derivative Assets (Liabilities) $ 1
$ 29
$ 5
$ —
$ (28 ) $ (1 ) $ 6

PSE&G
Net Derivative Assets (Liabilities) $ (5 ) $ —
$ 5
$ —
$ —
$ —
$ —

Power
Net Derivative Assets (Liabilities) $ 6
$ 29
$ —
$ —
$ (28 ) $ (1 ) $ 6

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

~~Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis~~

~~for the Three MonthsandNine Months Ended September 30, 2016~~

Three Months Ended September 30, 2016

Total Gains or (Losses)
Realized/Unrealized

Description Balance as of July 1, 2016
Included in
Income (E)

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

Transfers
In/Out
(D)
Balance as of September 30, 2016
Millions
PSEG
Net Derivative Assets (Liabilities) $ 5
$ 8
$ (2 ) $ 4
$ (4 ) $ —
$ 11

PSE&G
Net Derivative Assets (Liabilities) $ (2 ) $ —
$ (2 ) $ —
$ —
$ —
$ (4 )
Power
Net Derivative Assets (Liabilities) $ 7
$ 8
$ —
$ 4
$ (4 ) $ —
$ 15

Nine Months Ended September 30, 2016

Total Gains or (Losses)
Realized/Unrealized

Description Balance as of January 1, 2016
Included in
Income (E)

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

Transfers
In/Out (D)
Balance as of September 30, 2016

PSEG
Net Derivative Assets (Liabilities) $ 13
$ 24
$ (6 ) $ 4
$ (24 ) $ —
$ 11

PSE&G
Net Derivative Assets (Liabilities) $ 2
$ —
$ (6 ) $ —
$ —
$ —
$ (4 )
Power
Net Derivative Assets (Liabilities) $ 11
$ 24
$ —
$ 4
$ (24 ) $ —
$ 15


~~(A)~~	PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $3 million and $29 million in Operating Income for the three months and nine months ended September 30, 2017, respectively. The $3 million in Operating Income is realized. Of the $29 million in Operating Income, $1 million is unrealized.


~~(B)~~	Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Accumulated Other Comprehensive Income, as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers.


~~(C)~~	Represents $(3) million and $(28) million in settlements for the three months and nine months ended September 30, 2017, respectively. Represents $(4) million and $(24) million in settlements for the three months and nine months

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

~~ended September 30, 2016, respectively.~~


~~(D)~~	During the three months ended September 30, 2017 there were no transfers in to or out of Level 3. During the nine months ended September 30, 2017, $(1) million of net derivatives assets/liabilities were transferred from Level 2 to Level 3. There were no transfers in to or out of Level 3 during three months and nine months ended September 30, 2016.


~~(E)~~	PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $8 million and $24 million in Operating Income for the three months and nine months ended September 30, 2016, respectively. Of the $8 million in Operating Income, $4 million is unrealized. The $24 million in Operating Income is realized.

As of ~~September~~June 30, ~~2017,~~2023, PSEG carried ~~$2.6~~$3.1 billion of net assets that are measured at fair value on a recurring basis, of which $6$4 million of net ~~assets~~liabilities were measured using unobservable inputs and classified as Level 3 within the fair value ~~hierarchy.~~hierarchy and are considered immaterial.

As of ~~September~~June 30, ~~2016~~,2022, PSEG carried ~~$2.6~~$4.5 billion of net assets that are measured at fair value on a recurring basis, of which ~~$11~~$10 million of net ~~assets~~liabilities were measured using unobservable inputs and classified as Level 3 within the fair value ~~hierarchy.~~hierarchy and are considered immaterial.

There were no transfers to or from Level 3 during the six months ended June 30, 2023 and 2022, respectively.

Fair Value of Debt

The estimated fair values, ~~were determined using~~carrying amounts and methods used to determine the ~~market quotations or values~~fair value of ~~instruments with similar terms, credit ratings, remaining maturities and redemptions~~long-term debt as of ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016~~.2022 are included in the following table and accompanying notes.

As of As of
September 30, 2017 December 31, 2016

Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value

Millions
Long-Term Debt:
PSEG (Parent) (A) (B) $ 1,896
$ 1,891
$ 1,195
$ 1,185

PSE&G (B) 8,243
8,857
7,818
8,240

Power - Recourse Debt (B) 2,385
2,657
2,382
2,578

Total Long-Term Debt $ 12,524
$ 13,405
$ 11,395
$ 12,003

~~(A)~~

As of September 30, 2017, fair value includes a $700 million floating rate term loan in addition to the $500 million floating rate term loan and net offsets as of December 31, 2016. The fair values of the term loan debt (Level 2 measurement) approximate the carrying values because the interest payments are based on LIBOR rates that are reset monthly and the debt is redeemable at face value by PSEG at any time.

~~(B)~~

Given that these bonds do not trade actively, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk into the discount rates, pricing is obtained (i.e. U.S. Treasury rate plus credit spread) based on expected new issue pricing across each of the companies’ respective debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents



	As of				As of
	June 30, 2023				December 31, 2022
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (A)	$	4,127	$	3,828	$	4,124	$	3,808
PSE&G (A)	13,092		11,603		12,696		11,106
PSEG Power (B)	1,250		1,250		1,250		1,250
Total Long-Term Debt	$	18,469	$	16,681	$	18,070	$	16,164

~~Note 13. Other Income and Deductions~~(A)Given that these bonds do not trade actively, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model using market-based measurements that are processed through a rules-based pricing methodology. The fair value amounts above do not represent the price at which the outstanding debt may be called for redemption by each issuer under their respective debt agreements.

(B)Private term loan with book value approximating fair value (Level 2 measurement).

Other Income PSE&G Power Other (A) Consolidated
Millions
Three Months Ended September 30, 2017
NDT Fund Gains, Interest, Dividend and Other Income $ —
$ 41
$ —
$ 41

Allowance for Funds Used During Construction 14
—
—
14

Rabbi Trust Realized Gains, Interest and Dividends 1
1
—
2

Solar Loan Interest 6
—
—
6

Other 2
1
—
3

Total Other Income $ 23
$ 43
$ —
$ 66

Nine Months Ended September 30, 2017
NDT Fund Gains, Interest, Dividend and Other Income $ —
$ 117
$ —
$ 117

Allowance for Funds Used During Construction 42
—
—
42

Rabbi Trust Realized Gains, Interest and Dividends 5
6
11
22

Solar Loan Interest 16
—
—
16

Other 7
4
—
11

Total Other Income $ 70
$ 127
$ 11
$ 208

Three Months Ended September 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income $ —
$ 21
$ —
$ 21

Allowance for Funds Used During Construction 14
—
—
14

Rabbi Trust Realized Gains, Interest and Dividends 1
—
3
4

Solar Loan Interest 6
—
—
6

Other 1
2
(1 ) 2

Total Other Income $ 22
$ 23
$ 2
$ 47

Nine Months Ended September 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income $ —
$ 69
$ —
$ 69

Allowance for Funds Used During Construction 35
—
—
35

Rabbi Trust Realized Gains, Interest and Dividends 2
2
6
10

Solar Loan Interest 17
—
—
17

Other 7
3
(2 ) 8

Total Other Income $ 61
$ 74
$ 4
$ 139

Other Deductions PSE&G Power Other (A) Consolidated
Millions
Three Months Ended September 30, 2017
  NDT Fund Realized Losses and Expenses $ —
$ 8
$ —
$ 8

  Other 1
—
1
2

    Total Other Deductions $ 1
$ 8
$ 1
$ 10

Nine Months Ended September 30, 2017
  NDT Fund Realized Losses and Expenses $ —
$ 21
$ —
$ 21

  Other 3
1
5
9

    Total Other Deductions $ 3
$ 22
$ 5
$ 30

Three Months Ended September 30, 2016
  NDT Fund Realized Losses and Expenses $ —
$ 5
$ —
$ 5

  Other 1
1
1
3

  Total Other Deductions $ 1
$ 6
$ 1
$ 8

Nine Months Ended September 30, 2016
  NDT Fund Realized Losses and Expenses $ —
$ 31
$ —
$ 31

  Other 3
2
3
8

  Total Other Deductions $ 3
$ 33
$ 3
$ 39


~~(A)~~	~~Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations.~~

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Note 14. Other Income ~~Taxes~~(Deductions)

~~PSEG’s, PSE&G’s~~



	PSE&G		PSEG Power & Other (A)		Consolidated
	Millions
Three Months Ended June 30, 2023
NDT Fund Interest and Dividends	$	—	$	19	$	19
Allowance for Funds Used During Construction	15		—		15
Solar Loan Interest	2		—		2
Other Interest	5		9		14
Other	1		(2)		(1)
Total Other Income (Deductions)	$	23	$	26	$	49
Six Months Ended June 30, 2023
NDT Fund Interest and Dividends	$	—	$	34	$	34
Allowance for Funds Used During Construction	30		—		30
Solar Loan Interest	4		—		4
Other Interest	7		16		23
Other	3		(3)		—
Total Other Income (Deductions)	$	44	$	47	$	91
Three Months Ended June 30, 2022
NDT Fund Interest and Dividends	$	—	$	16	$	16
Allowance for Funds Used During Construction	15		—		15
Solar Loan Interest	3		—		3
Other Interest	2		2		4
Other	2		(2)		—
Total Other Income (Deductions)	$	22	$	16	$	38
Six Months Ended June 30, 2022
NDT Fund Interest and Dividends	$	—	$	30	$	30
Allowance for Funds Used During Construction	30		—		30
Solar Loan Interest	6		—		6
Purchases of Tax Losses under New Jersey Technology Tax Benefit Transfer Program	—		(27)		(27)
Other Interest	2		2		4
Other	3		(3)		—
Total Other Income (Deductions)	$	41	$	2	$	43

(A)PSEG Power & Other consists of activity at PSEG Power, Energy Holdings, PSEG LI, Services, PSEG ( parent company) and ~~Power’s effective tax rates for the three months and nine months ended~~ ~~September 30, 2017~~ ~~and 2016 were as follows:~~intercompany eliminations.

Three Months Ended Nine Months Ended
September 30, September 30,
2017 2016 2017 2016
PSEG 38.9% 36.5% 35.5% 36.3%
PSE&G 38.8% 36.1% 37.4% 36.1%
Power 41.9% 39.3% 37.9% 39.4%

For the three months and nine months ended September 30, 2017, the differences in PSEG’s effective tax rates as compared to the same periods in the prior year, as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions and the NDT Fund. For the nine months ended September 30, 2017, the effective tax rate was also favorably impacted by interest from a New Jersey State income tax refund.

For the three months and nine months ended September 30, 2017, the differences in PSE&G’s effective tax rates as compared to the same periods in the prior year, as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions, plant and other flow-through items.

For the three months and nine months ended September 30, 2017, the differences in Power’s effective tax rates as compared to the same periods in the prior year, as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions, manufacturing deduction and the NDT Fund.

PSEG’s federal tax returns for the years 2011 and 2012 are currently being audited by the IRS. The audit and other related claims are reasonably expected to be completed within the next 12 months. As a result, it is reasonably possible that a decrease in PSEG’s total unrecognized tax benefits may be necessary in the range of $80 million to $180 million based on current estimates.

The Protecting Americans from Tax Hikes Act of 2015 (Tax Act) extended the 50% bonus depreciation rules for qualified property placed in service from January 1, 2015 through December 31, 2017. The rate is reduced to 40% and 30% for eligible property placed in service in 2018 and 2019, respectively. On May 8, 2017 the IRS issued guidance allowing for 50% bonus depreciation on long production property that is placed in service in 2018. For long production property placed in service in 2019, qualified costs incurred before January 1, 2019 is afforded a 40% rate, while qualified costs incurred during 2019 receives a 30% rate. For long production property placed in service in 2020, subject to a written binding contract entered into before 2020, a 30% rate is allowed for qualified costs incurred before January 1, 2020, with a 0% rate thereafter. The Tax Act also extended the 30% ITC for qualified property placed in service starting January 1, 2016 through December 31, 2019 but reduces the ITC rate to 26% and 22% for projects commenced in 2020 and 2021, respectively. The financial impact of the extensions of the ITC rate will depend upon future transactions.

This provision has generated significant cash tax benefits for PSEG, PSE&G and Power through tax benefits related to the accelerated depreciation. These tax benefits would have otherwise been received over an estimated average 20 year period. However, these tax benefits will have a negative impact on the rate base of several of PSE&G’s programs.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Note 15. Income Taxes

A reconciliation of reported income tax expense for PSEG with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% is as follows:



	Three Months Ended						Six Months Ended
PSEG	June 30,						June 30,
	2023			2022			2023			2022
	Millions
Pre-Tax Income (Loss)	$	744		$	98		$	2,329		$	(56)
Tax Computed at Statutory Rate @ 21%	$	156		$	21		$	489		$	(12)
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)	50			6			158			(22)
NDT Fund	7			(18)			13			(24)
Uncertain Tax Positions	(1)			—			(7)			(2)
Leasing Activities	—			—			(17)			—
GPRC-CEF-EE	(8)			(8)			(24)			(14)
Tax Credits	(3)			(2)			(5)			(4)
Estimated Annual Effective Tax Rate Interim Period Adjustment	7			4			(16)			(8)
TAC	(51)			(32)			(126)			(106)
Other	(4)			(4)			(14)			7
Subtotal	(3)			(54)			(38)			(173)
Total Income Tax Expense (Benefit)	$	153		$	(33)		$	451		$	(185)
Effective Income Tax Rate	20.6		%	(33.7)		%	19.4		%	N/A

A reconciliation of reported income tax expense for PSE&G with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% is as follows:



	Three Months Ended						Six Months Ended
PSE&G	June 30,						June 30,
	2023			2022			2023			2022
	Millions
Pre-Tax Income	$	370		$	361		$	911		$	959
Tax Computed at Statutory Rate @ 21%	$	78		$	76		$	191		$	201
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)	30			25			68			67
Uncertain Tax Positions	(6)			—			(6)			—
Tax Credits	(3)			(2)			(5)			(4)
GPRC-CEF-EE	(8)			(8)			(24)			(14)
TAC	(51)			(32)			(126)			(106)
Other	(6)			(3)			(10)			1
Subtotal	(44)			(20)			(103)			(56)
Total Income Tax Expense (Benefit)	$	34		$	56		$	88		$	145
Effective Income Tax Rate	9.2		%	15.5		%	9.7		%	15.1		%

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

PSEG’s and PSE&G’s total income tax expense (benefit) for interim periods is determined using an estimated annual effective tax rate, adjusted for discrete items, if any, that are taken into account in the relevant period. Each quarter, PSEG and PSE&G update the respective estimated annual effective tax rates, and if the estimated tax rate changes, PSEG and PSE&G make cumulative adjustments.

A prolonged economic recovery can result in the enactment of additional federal and state tax legislation. Enactment of additional legislation and clarification of prior enacted tax laws could impact PSEG’s and PSE&G’s financial statements.

In August 2022, the IRA was signed into law. The IRA made certain changes to existing energy tax credit laws and enacted a new 15% corporate alternative minimum tax (CAMT), effective in 2023. Changes to the energy tax credit laws include: increases to the PTC rate, a new PTC for electricity generation using nuclear energy, expanded technologies that are eligible for energy tax credits, and the transferability of the energy tax credits. See Note 3. Early Plant Retirements/Asset Dispositions and Impairments for additional information on the nuclear PTC.

Since the enactment of the IRA, the U.S. Treasury issued various Notices that provide interim guidance on several provisions of the IRA, including the CAMT. The Notices state that the U.S. Treasury anticipates issuing additional guidance including proposed and final regulations. Many aspects of the IRA remain unclear and in need of further guidance; therefore, the impact the IRA will have on PSEG's and PSE&G's financial statements is subject to continued evaluation.

In April 2023, the U.S. Treasury issued Revenue Procedure 2023-15 that provides a safe harbor method of accounting to determine the annual repair tax deduction for gas transmission and distribution property. The impact, if any, this may have on PSEG and PSE&G’s financial statements has not yet been determined.

As of June 30, 2023, PSEG had a $44 million state net operating loss (NOL) and PSE&G had a $50 million New Jersey Corporate Business Tax NOL that are both expected to be fully realized in the future.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Note 16. Accumulated Other Comprehensive Income (Loss), Net of Tax



	Three Months Ended June 30, 2023
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans		Available-for-Sale Securities		Total
	Millions
Balance as of March 31, 2023	$	(4)	$	(423)	$	(95)	$	(522)
Other Comprehensive Income (Loss) before Reclassifications	12		—		(12)		—
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(1)		4		4		7
Net Current Period Other Comprehensive Income (Loss)	11		4		(8)		7
Balance as of June 30, 2023	$	7	$	(419)	$	(103)	$	(515)

	Three Months Ended June 30, 2022
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans		Available-for-Sale Securities		Total
	Millions
Balance as of March 31, 2022	$	(5)	$	(355)	$	(50)	$	(410)
Other Comprehensive Income (Loss) before Reclassifications	—		—		(53)		(53)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		1		7		8
Net Current Period Other Comprehensive Income (Loss)	—		1		(46)		(45)
Balance as of June 30, 2022	$	(5)	$	(354)	$	(96)	$	(455)


	Six Months Ended June 30, 2023
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans		Available-for-Sale Securities		Total
	Millions
Balance as of December 31, 2022	$	(3)	$	(426)	$	(121)	$	(550)
Other Comprehensive Income (Loss) before Reclassifications	10		—		8		18
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		7		10		17
Net Current Period Other Comprehensive Income (Loss)	10		7		18		35
Balance as of June 30, 2023	$	7	$	(419)	$	(103)	$	(515)

	Six Months Ended June 30, 2022
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans		Available-for-Sale Securities		Total
	Millions
Balance as of December 31, 2021	$	(6)	$	(355)	$	11	$	(350)
Other Comprehensive Income (Loss) before Reclassifications	—		—		(118)		(118)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	1		1		11		13
Net Current Period Other Comprehensive Income (Loss)	1		1		(107)		(105)
Balance as of June 30, 2022	$	(5)	$	(354)	$	(96)	$	(455)

PSEG Other Comprehensive Income (Loss)
Three Months Ended September 30, 2017
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of June 30, 2017 $ 2
$ (386 ) $ 158
$ (226 )
Other Comprehensive Income before Reclassifications —
—
25
25

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (1 ) 6
(8 ) (3 )
Net Current Period Other Comprehensive Income (Loss) (1 ) 6
17
22

Balance as of September 30, 2017 $ 1
$ (380 ) $ 175
$ (204 )

PSEG Other Comprehensive Income (Loss)
Three Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of June 30, 2016 $ 1
$ (370 ) $ 117
$ (252 )
Other Comprehensive Income before Reclassifications 1
—
26
27

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
9
(2 ) 7

Net Current Period Other Comprehensive Income (Loss) 1
9
24
34

Balance as of September 30, 2016 $ 2
$ (361 ) $ 141
$ (218 )

PSEG Other Comprehensive Income (Loss)
Nine Months Ended September 30, 2017
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of December 31, 2016 $ 2
$ (398 ) $ 133
$ (263 )
Other Comprehensive Income before Reclassifications —
—
78
78

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (1 ) 18
(36 ) (19 )
Net Current Period Other Comprehensive Income (Loss) (1 ) 18
42
59

Balance as of September 30, 2017 $ 1
$ (380 ) $ 175
$ (204 )

PSEG Other Comprehensive Income (Loss)
Nine Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of December 31, 2015 $ —
$ (386 ) $ 91
$ (295 )
Other Comprehensive Income before Reclassifications 2
—
44
46

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
25
6
31

Net Current Period Other Comprehensive Income (Loss) 2
25
50
77

Balance as of September 30, 2016 $ 2
$ (361 ) $ 141
$ (218 )

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents



		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended						Six Months Ended
		June 30, 2023						June 30, 2023
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount		Tax (Expense) Benefit		After-Tax Amount		Pre-Tax Amount		Tax (Expense) Benefit		After-Tax Amount
		Millions
Cash Flow Hedges
Interest Rate Swaps	Interest Expense	$	1	$	—	$	1	$	—	$	—	$	—
Total Cash Flow Hedges		1		—		1		—		—		—
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	Non-Operating Pension and OPEB Credits (Costs)	2		(1)		1		4		(1)		3
Amortization of Actuarial Loss	Non-Operating Pension and OPEB Credits (Costs)	(7)		2		(5)		(14)		4		(10)
Total Pension and OPEB Plans		(5)		1		(4)		(10)		3		(7)
Available-for-Sale Debt Securities
Realized Gains (Losses)	Net Gains (Losses) on Trust Investments	(7)		3		(4)		(17)		7		(10)
Total Available-for-Sale Debt Securities		(7)		3		(4)		(17)		7		(10)
Total		$	(11)	$	4	$	(7)	$	(27)	$	10	$	(17)

Power Other Comprehensive Income (Loss)
Three Months Ended September 30, 2017
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of June 30, 2017 $ —
$ (330 ) $ 158
$ (172 )
Other Comprehensive Income before Reclassifications —
—
24
24

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
5
(9 ) (4 )
Net Current Period Other Comprehensive Income (Loss) —
5
15
20

Balance as of September 30, 2017 $ —
$ (325 ) $ 173
$ (152 )

Power Other Comprehensive Income (Loss)
Three Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of June 30, 2016 $ —
$ (313 ) $ 112
$ (201 )
Other Comprehensive Income before Reclassifications —
—
24
24

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
7
(2 ) 5

Net Current Period Other Comprehensive Income (Loss) —
7
22
29

Balance as of September 30, 2016 $ —
$ (306 ) $ 134
$ (172 )

Power Other Comprehensive Income (Loss)
Nine Months Ended September 30, 2017
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of December 31, 2016 $ —
$ (340 ) $ 129
$ (211 )
Other Comprehensive Income before Reclassifications —
—
74
74

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
15
(30 ) (15 )
Net Current Period Other Comprehensive Income (Loss) —
15
44
59

Balance as of September 30, 2017 $ —
$ (325 ) $ 173
$ (152 )

Power Other Comprehensive Income (Loss)
Nine Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of December 31, 2015 $ —
$ (327 ) $ 87
$ (240 )
Other Comprehensive Income before Reclassifications —
—
40
40

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
21
7
28

Net Current Period Other Comprehensive Income (Loss) —
21
47
68

Balance as of September 30, 2016 $ —
$ (306 ) $ 134
$ (172 )

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents



		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended						Six Months Ended
		June 30, 2022						June 30, 2022
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount		Tax (Expense) Benefit		After-Tax Amount		Pre-Tax Amount		Tax (Expense) Benefit		After-Tax Amount
		Millions
Cash Flow Hedges
Interest Rate Swaps	Interest Expense	$	(1)	$	1	$	—	$	(2)	$	1	$	(1)
Total Cash Flow Hedges		(1)		1		—		(2)		1		(1)
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	Non-Operating Pension and OPEB Credits (Costs)	5		(2)		3		10		(3)		7
Amortization of Actuarial Loss	Non-Operating Pension and OPEB Credits (Costs)	(6)		2		(4)		(11)		3		(8)
Total Pension and OPEB Plans		(1)		—		(1)		(1)		—		(1)
Available-for-Sale Debt Securities
Realized Gains (Losses)	Net Gains (Losses) on Trust Investments	(12)		5		(7)		(18)		7		(11)
Total Available-for-Sale Debt Securities		(12)		5		(7)		(18)		7		(11)
Total		$	(14)	$	6	$	(8)	$	(21)	$	8	$	(13)

PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Three Months Ended Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2017 September 30, 2017
Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Cash Flow Hedges
Interest Rate Swaps Interest Expense $ 2
$ (1 ) $ 1
$ 2
$ (1 ) $ 1

Total Cash Flow Hedges 2
(1 ) 1
2
(1 ) 1

Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit O&M Expense 3
(1 ) 2
7
(3 ) 4

Amortization of Actuarial Loss O&M Expense (13 ) 5
(8 ) (37 ) 15
(22 )
Total Pension and OPEB Plans (10 ) 4
(6 ) (30 ) 12
(18 )
Available-for-Sale Securities
Realized Gains Other Income 29
(15 ) 14
99
(49 ) 50

Realized Losses Other Deductions (6 ) 2
(4 ) (19 ) 9
(10 )
OTTI OTTI (5 ) 3
(2 ) (9 ) 5
(4 )
Total Available-for-Sale Securities 18
(10 ) 8
71
(35 ) 36

Total $ 10
$ (7 ) $ 3
$ 43
$ (24 ) $ 19

PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Three Months Ended Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2016 September 30, 2016
Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit O&M Expense $ 3
$ (2 ) $ 1
$ 9
$ (4 ) $ 5

Amortization of Actuarial Loss O&M Expense (17 ) 7
(10 ) (51 ) 21
(30 )
Total Pension and OPEB Plans (14 ) 5
(9 ) (42 ) 17
(25 )
Available-for-Sale Securities
Realized Gains Other Income 13
(6 ) 7
41
(20 ) 21

Realized Losses Other Deductions (5 ) 3
(2 ) (29 ) 15
(14 )
OTTI OTTI (5 ) 2
(3 ) (25 ) 12
(13 )
Total Available-for-Sale Securities 3
(1 ) 2
(13 ) 7
(6 )
Total $ (11 ) $ 4
$ (7 ) $ (55 ) $ 24
$ (31 )

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Three Months Ended Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2017 September 30, 2017
Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit O&M Expense $ 2
$ (1 ) $ 1
$ 6
$ (3 ) $ 3

Amortization of Actuarial Loss O&M Expense (11 ) 5
(6 ) (32 ) 14
(18 )
Total Pension and OPEB Plans (9 ) 4
(5 ) (26 ) 11
(15 )
Available-for-Sale Securities
Realized Gains Other Income 29
(15 ) 14
86
(44 ) 42

Realized Losses Other Deductions (5 ) 2
(3 ) (15 ) 7
(8 )
OTTI OTTI (5 ) 3
(2 ) (9 ) 5
(4 )
Total Available-for-Sale Securities 19
(10 ) 9
62
(32 ) 30

Total $ 10
$ (6 ) $ 4
$ 36
$ (21 ) $ 15

Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Three Months Ended Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2016 September 30, 2016
Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit O&M Expense $ 3
$ (1 ) $ 2
$ 8
$ (3 ) $ 5

Amortization of Actuarial Loss O&M Expense (15 ) 6
(9 ) (44 ) 18
(26 )
Total Pension and OPEB Plans (12 ) 5
(7 ) (36 ) 15
(21 )
Available-for-Sale Securities
Realized Gains Other Income 12
(5 ) 7
37
(18 ) 19

Realized Losses Other Deductions (4 ) 2
(2 ) (26 ) 13
(13 )
OTTI OTTI (5 ) 2
(3 ) (25 ) 12
(13 )
Total Available-for-Sale Securities 3
(1 ) 2
(14 ) 7
(7 )
Total $ (9 ) $ 4
$ (5 ) $ (50 ) $ 22
$ (28 )

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

Note ~~16.~~17. Earnings Per Share (EPS) and Dividends

EPS

Basic EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding. Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, ~~including~~plus dilutive potential shares ~~issuable upon exercise of stock options outstanding or vesting of restricted stock awards granted under~~related to PSEG’s stock ~~compensation plans and upon payment of performance units or restricted stock units.~~based compensation. The following table shows the effect of these ~~stock options, performance units and restricted stock units~~dilutive potential shares on the weighted average number of shares outstanding used in calculating diluted EPS:

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Basic Diluted Basic Diluted Basic Diluted Basic Diluted

EPS Numerator (Millions):

Net Income $ 395
$ 395
$ 327
$ 327
$ 618
$ 618
$ 985
$ 985

EPS Denominator (Millions):

Weighted Average Common Shares Outstanding 505
505
505
505
505
505
505
505

Effect of Stock Based Compensation Awards —
2
—
3
—
2
—
3

Total Shares 505
507
505
508
505
507
505
508

EPS
Net Income $ 0.78
$ 0.78
$ 0.65
$ 0.64
$ 1.22
$ 1.22
$ 1.95
$ 1.94

There were approximately 0.3 million for the three months and nine months ended September 30, 2017 and approximately 0.4 million for the three months and nine months ended September 30, 2016 of stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect.

~~Dividends~~



	Three Months Ended June 30,								Six Months Ended June 30,
	2023				2022				2023				2022
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions):
Net Income	$	591	$	591	$	131	$	131	$	1,878	$	1,878	$	129	$	129
EPS Denominator (Millions):
Weighted Average Common Shares Outstanding	497		497		497		497		497		497		499		499
Effect of Stock Based Compensation Awards	—		3		—		3		—		3		—		3
Total Shares	497		500		497		500		497		500		499		502

EPS
Net Income	$	1.19	$	1.18	$	0.26	$	0.26	$	3.78	$	3.76	$	0.26	$	0.26

Three Months Ended Nine Months Ended
September 30, September 30,
Dividend Payments on Common Stock 2017 2016 2017 2016
Per Share $ 0.43
$ 0.41
$ 1.29
$ 1.23

In Millions $ 217
$ 207
$ 652
$ 622

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Dividends



	Three Months Ended				Six Months Ended
	June 30,				June 30,
Dividend Payments on Common Stock	2023		2022		2023		2022
Per Share	$	0.57	$	0.54	$	1.14	$	1.08
In Millions	$	285	$	270	$	569	$	541

On July 17, 2023, PSEG’s Board of Directors approved a $0.57 per share common stock dividend for the third quarter of 2023.

Note ~~17.~~18. Financial Information by Business Segment

Basis of Organization

PSEG’s and PSE&G’s operating segments were determined by management in accordance with GAAP. These segments were determined based on how the Chief Operating Decision Maker (CODM) (the Chief Executive Officer (CEO) for PSEG and PSE&G), measures performance based on segment Net Income and how resources are allocated to each business.

Following completion of the sale of the PSEG Power Fossil portfolio in February 2022 and as a result of the transition to a new CEO, our designated CODM, effective September 1, 2022, various changes were made to the content and manner in which the new CEO reviews financial information for purposes of assessing business performance and allocating resources. Based on management’s analysis, PSE&G and PSEG Power were determined to remain operating segments of PSEG. However, PSEG has revised its reportable segments for the year ended December 31, 2022 to PSE&G and PSEG Power & Other. PSE&G continues to be PSEG’s principal reportable segment. The PSEG Power & Other reportable segment includes amounts related to the PSEG Power operating segment as well as amounts applicable to Energy Holdings, PSEG LI, PSEG (parent company) and Services, which do not meet the definition of operating segments individually or in the aggregate and are immaterial to PSEG’s consolidated assets and results. All prior period comparative information has been restated to reflect the change in segment presentation.

PSE&G

PSE&G earns revenues from its tariffs, under which it provides electric transmission and electric and gas distribution services to residential, commercial and industrial customers in New Jersey. The rates charged for electric transmission are regulated by FERC while the rates charged for electric and gas distribution are regulated by the BPU. Revenues are also earned from several other activities such as investments in EE equipment on customers’ premises, solar investments, the appliance service business and other miscellaneous services.

PSEG Power & Other

This reportable segment is comprised primarily of PSEG Power which earns revenues primarily by bidding energy, capacity and ancillary services into the markets for these products and by selling energy, capacity and ancillary services on a wholesale basis under contract to power marketers and to load-serving entities. PSEG Power also enters into bilateral contracts for energy, capacity, FTRs, gas, emission allowances and other energy-related contracts to optimize the value of its portfolio of generating assets and its electric and gas supply obligations. In addition, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants receive ZEC revenue from the EDCs in New Jersey including PSE&G.

This reportable segment also includes amounts applicable to PSEG LI, which generates revenues under its contract with LIPA, primarily for the recovery of costs when Servco is a principal in the transaction (see Note 4. Variable Interest Entity for additional information) as well as fixed and variable fee components under the contract, and Energy Holdings which holds an immaterial portfolio of remaining lease investments. Other also includes amounts applicable to PSEG (parent company) and Services.

PSE&G Power Other (A) Eliminations (B) Consolidated Total
Millions
Three Months Ended September 30, 2017
Total Operating Revenues $ 1,509
$ 873
$ 135
$ (254 ) $ 2,263

Net Income (Loss) 246
136
13
—
395

Gross Additions to Long-Lived Assets 729
327
9
—
1,065

Nine Months Ended September 30, 2017
Operating Revenues $ 4,689
$ 3,086
$ 334
$ (1,121 ) $ 6,988

Net Income (Loss) 753
(131 ) (4 ) —
618

Gross Additions to Long-Lived Assets 2,118
903
25
—
3,046

Three Months Ended September 30, 2016
Total Operating Revenues $ 1,684
$ 1,075
$ 7
$ (316 ) $ 2,450

Net Income (Loss) 255
139
(67 ) —
327

Gross Additions to Long-Lived Assets 680
325
9
—
1,014

Nine Months Ended September 30, 2016
Operating Revenues $ 4,746
$ 3,102
$ 256
$ (1,133 ) $ 6,971

Net Income (Loss) 696
320
(31 ) —
985

Gross Additions to Long-Lived Assets 2,035
923
27
—
2,985

As of September 30, 2017
Total Assets $ 27,802
$ 11,631
$ 2,288
$ (564 ) $ 41,157

Investments in Equity Method Subsidiaries $ —
$ 90
$ —
$ —
$ 90

As of December 31, 2016
Total Assets $ 26,288
$ 12,193
$ 2,373
$ (784 ) $ 40,070

Investments in Equity Method Subsidiaries $ —
$ 102
$ —
$ —
$ 102


~~(A)~~	Includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services.

~~(B)~~

Intercompany eliminations relate primarily to intercompany transactions between PSE&G and Power. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between PSE&G and Power, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 18. Related-Party Transactions.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents



	PSE&G		PSEG Power & Other		Eliminations (A)		Consolidated Total
	Millions
Three Months Ended June 30, 2023
Operating Revenues	$	1,662	$	902	$	(143)	$	2,421
Net Income (B)	336		255		—		591
Gross Additions to Long-Lived Assets	660		45		—		705
Six Months Ended June 30, 2023
Operating Revenues	$	3,955	$	2,929	$	(708)	$	6,176
Net Income (B)	823		1,055		—		1,878
Gross Additions to Long-Lived Assets	1,336		108		—		1,444
Three Months Ended June 30, 2022
Operating Revenues	$	1,668	$	645	$	(237)	$	2,076
Net Income (Loss) (B)	305		(174)		—		131
Gross Additions to Long-Lived Assets	543		62		—		605
Six Months Ended June 30, 2022
Operating Revenues	$	3,952	$	1,258	$	(821)	$	4,389
Net Income (Loss) (B)	814		(685)		—		129
Gross Additions to Long-Lived Assets	1,171		120		—		1,291
As of June 30, 2023
Total Assets	$	41,347	$	8,505	$	(347)	$	49,505
Investments in Equity Method Subsidiaries	$	—	$	15	$	—	$	15
As of December 31, 2022
Total Assets	$	39,960	$	9,285	$	(527)	$	48,718
Investments in Equity Method Subsidiaries	$	—	$	306	$	—	$	306

(A)Intercompany eliminations primarily relate to intercompany transactions between PSE&G and PSEG Power. For a further discussion of the intercompany transactions between PSE&G and PSEG Power, see Note 19. Related-Party Transactions.

(B)Includes net after-tax gains (losses) of $212 million and $(74) million for the three months and $767 million and $(682) million for the six months ended June 30, 2023 and 2022, respectively, at PSEG Power related to the impacts of non-trading commodity mark-to-market activity, which consist of the financial impact from positions with future delivery dates.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Note ~~18.~~19. Related-Party Transactions

The following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP.

PSE&G

The financial statements for PSE&G include transactions with related parties ~~as follows:~~

Three Months Ended Nine Months Ended
September 30, September 30,
Related-Party Transactions 2017 2016 2017 2016
Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A) $ 259
$ 320
$ 1,154
$ 1,162

Administrative Billings from Services (B) 82
73
226
224

Total Billings from Affiliates $ 341
$ 393
$ 1,380
$ 1,386

As of As of
Related-Party Transactions September 30, 2017 December 31, 2016
Millions
Receivables from PSEG (C) $ —
$ 76

Payable to Power (A) $ 86
$ 193

Payable to Services (B) 46
67

Payable to PSEG (C) 46
—

Accounts Payable—Affiliated Companies $ 178
$ 260

Working Capital Advances to Services (D) $ 33
$ 33

Long-Term Accrued Taxes Payable
$ 83
$ 130

~~Power~~

~~The financial statements for Power include transactions with related parties~~presented as follows:



	Three Months Ended				Six Months Ended
	June 30,				June 30,
Related-Party Transactions	2023		2022		2023		2022
	Millions
Billings from Affiliates:
Net Billings from PSEG Power (A)	$	114	$	232	$	675	$	812
Administrative Billings from Services (B)	118		113		220		212
Total Billings from Affiliates	$	232	$	345	$	895	$	1,024

Three Months Ended Nine Months Ended
September 30, September 30,
Related-Party Transactions 2017 2016 2017 2016
Millions
Billings to Affiliates:
Net Billings to PSE&G primarily through BGS and BGSS (A) $ 259
$ 320
$ 1,154
$ 1,162

Billings from Affiliates:
Administrative Billings from Services (B) $ 39
$ 44
$ 117
$ 134



	As of		As of
Related-Party Transactions	June 30, 2023		December 31, 2022
	Millions



Payable to PSEG Power (A)	$	192	$	313
Payable to Services (B)	88		98
Payable to PSEG (C)	16		74
Accounts Payable—Affiliated Companies	$	296	$	485
Noncurrent Payable to PSEG Power (A)	$	10	$	—
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	8	$	9

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

As of As of
Related-Party Transactions September 30, 2017 December 31, 2016
Millions
Receivables from PSE&G (A) $ 86
$ 193

Receivables from PSEG (C) —
12

Accounts Receivable—Affiliated Companies $ 86
$ 205

Payable to Services (B) $ 17
$ 25

Payable to PSEG (C) 111
—

Accounts Payable—Affiliated Companies $ 128
$ 25

Short-Term Loan Due (to) from Affiliate (E) $ 1
$ 87

Working Capital Advances to Services (D) $ 17
$ 17

Long-Term Accrued Taxes Payable
$ 57
$ 77

~~(A)~~

(A)PSE&G has ~~entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. Power has also~~ entered into a requirements contract with PSEG Power under which PSEG Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. Since June 1, 2022, PSEG Power had no contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. In addition, PSEG Power sells ZECs to PSE&G from its nuclear units under the ZEC program as approved by the BPU. The rates in the BGS and BGSS contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. In addition, Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules.


~~(B)~~	Services provides and bills administrative services to PSE&G and Power at cost. In addition, PSE&G and Power have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies.

~~(C)~~

PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits.


~~(D)~~	~~PSE&G and Power have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on PSE&G’s and Power’s Condensed Consolidated Balance Sheets.~~


~~(E)~~	~~Power’s short-term loans with PSEG are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

~~Note 19. Guarantees of Debt~~

Power’s Senior Notes are fully and unconditionally and jointly and severally guaranteed by its subsidiaries, PSEG Fossil LLC, PSEG Nuclear LLC and PSEG Energy Resources & Trade LLC. The following tables present condensed financial information for the guarantor subsidiaries, as well as Power’s non-guarantor subsidiaries, as of September 30, 2017 and December 31, 2016 and for the ~~three months~~ZEC sales are prescribed by the BPU. BGS and ~~nine months ended September 30, 2017~~BGSS sales are billed and ~~2016.~~settled on a monthly basis. ZEC sales are billed on a monthly basis and settled annually following completion of each energy year. In addition, PSEG Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules.

(B)Services provides and bills administrative services to PSE&G at cost. In addition, PSE&G has other payables to Services, including amounts related to certain common costs, which Services pays on behalf of PSE&G.

(C)PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are NOLs and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits. In addition, PSEG pays all payroll taxes and receives reimbursement from its affiliated companies for their respective portions.

(D)PSE&G has advanced working capital to Services. The amount is included in Other Noncurrent Assets on PSE&G’s Condensed Consolidated Balance Sheets.

Power
Guarantor
Subsidiaries

Other
Subsidiaries

Consolidating
Adjustments
Total
Millions
Three Months Ended September 30, 2017
Operating Revenues $ —
$ 856
$ 46
$ (29 ) $ 873

Operating Expenses 2
643
44
(29 ) 660

Operating Income (Loss) (2 ) 213
2
—
213

Equity Earnings (Losses) of Subsidiaries 143
(3 ) 3
(140 ) 3

Other Income 24
58
(2 ) (37 ) 43

Other Deductions —
(8 ) —
—
(8 )
Other-Than-Temporary Impairments —
(5 ) —
—
(5 )
Interest Expense (32 ) (12 ) (5 ) 37
(12 )
Income Tax Benefit (Expense) 3
(103 ) 2
—
(98 )
Net Income (Loss) $ 136
$ 140
$ —
$ (140 ) $ 136

Comprehensive Income (Loss) $ 156
$ 154
$ —
$ (154 ) $ 156

Nine Months Ended September 30, 2017
Operating Revenues $ —
$ 3,036
$ 145
$ (95 ) $ 3,086

Operating Expenses 4
3,315
139
(95 ) 3,363

Operating Income (Loss) (4 ) (279 ) 6
—
(277 )
Equity Earnings (Losses) of Subsidiaries (111 ) (8 ) 11
119
11

Other Income 71
155
—
(99 ) 127

Other Deductions (1 ) (21 ) —
—
(22 )
Other-Than-Temporary Impairments —
(9 ) —
—
(9 )
Interest Expense (96 ) (30 ) (14 ) 99
(41 )
Income Tax Benefit (Expense) 10
68
2
—
80

Net Income (Loss) $ (131 ) $ (124 ) $ 5
$ 119
$ (131 )
Comprehensive Income (Loss) $ (72 ) $ (80 ) $ 5
$ 75
$ (72 )
Nine Months Ended September 30, 2017

Net Cash Provided By (Used In)
   Operating Activities
$ (55 ) $ 1,159
$ 142
$ 3
$ 1,249

Net Cash Provided By (Used In)
   Investing Activities
$ 738
$ (289 ) $ (343 ) $ (990 ) $ (884 )

Net Cash Provided By (Used In)
   Financing Activities
$ (683 ) $ (869 ) $ 211
$ 987
$ (354 )

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

Power
Guarantor
Subsidiaries

Other
Subsidiaries

Consolidating
Adjustments
Total
Millions
Three Months Ended September 30, 2016
Operating Revenues $ —
$ 1,059
$ 43
$ (27 ) $ 1,075

Operating Expenses (2 ) 826
40
(27 ) 837

Operating Income (Loss) 2
233
3
—
238

Equity Earnings (Losses) of Subsidiaries 143
(1 ) 3
(142 ) 3

Other Income 18
26
—
(21 ) 23

Other Deductions (2 ) (4 ) —
—
(6 )
Other-Than-Temporary Impairments —
(5 ) —
—
(5 )
Interest Expense (30 ) (12 ) (3 ) 21
(24 )
Income Tax Benefit (Expense) 8
(97 ) (1 ) —
(90 )
Net Income (Loss) $ 139
$ 140
$ 2
$ (142 ) $ 139

Comprehensive Income (Loss) $ 168
$ 161
$ 2
$ (163 ) $ 168

Nine Months Ended September 30, 2016
Operating Revenues $ —
$ 3,061
$ 131
$ (90 ) $ 3,102

Operating Expenses 10
2,494
119
(90 ) 2,533

Operating Income (Loss) (10 ) 567
12
—
569

Equity Earnings (Losses) of Subsidiaries 347
(1 ) 9
(346 ) 9

Other Income 52
88
—
(66 ) 74

Other Deductions (2 ) (31 ) —
—
(33 )
Other-Than-Temporary Impairments —
(25 ) —
—
(25 )
Interest Expense (91 ) (29 ) (12 ) 66
(66 )
Income Tax Benefit (Expense) 24
(234 ) 2
—
(208 )
Net Income (Loss) $ 320
$ 335
$ 11
$ (346 ) $ 320

Comprehensive Income (Loss) $ 388
$ 381
$ 11
$ (392 ) $ 388

Nine Months Ended September 30, 2016

Net Cash Provided By (Used In)
   Operating Activities
$ 175
$ 1,261
$ 234
$ (410 ) $ 1,260

Net Cash Provided By (Used In)
   Investing Activities
$ (588 ) $ (1,166 ) $ (549 ) $ 1,152
$ (1,151 )

Net Cash Provided By (Used In)
   Financing Activities
$ 413
$ (95 ) $ 315
$ (742 ) $ (109 )

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

Power
Guarantor
Subsidiaries

Other
Subsidiaries

Consolidating
Adjustments
Total
Millions
As of September 30, 2017
Current Assets $ 4,089
$ 1,324
$ 182
$ (4,433 ) $ 1,162

Property, Plant and Equipment, net 57
5,408
2,607
—
8,072

Investment in Subsidiaries 4,168
338
—
(4,506 ) —

Noncurrent Assets 184
2,211
116
(114 ) 2,397

Total Assets $ 8,498
$ 9,281
$ 2,905
$ (9,053 ) $ 11,631

Current Liabilities $ 233
$ 3,221
$ 1,743
$ (4,433 ) $ 764

Noncurrent Liabilities 503
2,192
524
(114 ) 3,105

Long-Term Debt 2,385
—
—
—
2,385

Member’s Equity 5,377
3,868
638
(4,506 ) 5,377

Total Liabilities and Member’s Equity $ 8,498
$ 9,281
$ 2,905
$ (9,053 ) $ 11,631

As of December 31, 2016
Current Assets $ 4,412
$ 1,593
$ 152
$ (4,697 ) $ 1,460

Property, Plant and Equipment, net 55
6,145
2,320
—
8,520

Investment in Subsidiaries 4,249
344
—
(4,593 ) —

Noncurrent Assets 168
2,016
129
(100 ) 2,213

Total Assets $ 8,884
$ 10,098
$ 2,601
$ (9,390 ) $ 12,193

Current Liabilities $ 171
$ 3,752
$ 1,454
$ (4,697 ) $ 680

Noncurrent Liabilities 532
2,398
502
(100 ) 3,332

Long-Term Debt 2,382
—
—
—
2,382

Member’s Equity 5,799
3,948
645
(4,593 ) 5,799

Total Liabilities and Member’s Equity $ 8,884
$ 10,098
$ 2,601
$ (9,390 ) $ 12,193

Table of Contents

ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)


~~ITEM 2.~~	~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)~~

This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG), and Public Service Electric and Gas Company (PSE&G) ~~and PSEG Power LLC (Power)~~. Information contained herein relating to any individual company is filed by such company on its own behalf. ~~PSE&G and Power each make representations only as to itself and make no representations whatsoever as to any other company.~~

PSEG’s business consists of two reportable segments, PSE&G and PSEG Power LLC (PSEG Power) & Other, primarily comprised of our principal direct wholly owned subsidiaries, which are:

•PSE&G—which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) ~~and~~, the Federal Energy Regulatory Commission (FERC)., and other federal and New Jersey state regulators. PSE&G also invests in regulated solar generation projects and ~~has implemented~~ energy efficiency (EE) and related programs in New Jersey, which are regulated by the BPU, and

•PSEG Power—which is ~~a multi-regional~~an energy supply company that integrates the operations of its merchant nuclear ~~and fossil~~ generating assets with its ~~power marketing businesses and~~ fuel supply functions through competitive energy sales ~~in well-developed energy markets primarily in the Northeast and Mid-Atlantic United States through~~via its principal direct wholly owned subsidiaries. ~~In addition, Power owns and operates solar generation in various states.~~PSEG Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC)~~, the Environmental Protection Agency (EPA)~~ and other federal regulators and state regulators in the states in which they operate.

The PSEG Power & Other reportable segment also includes amounts related to the parent company as well as PSEG’s other direct wholly owned subsidiaries, ~~include~~which are: PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily ~~has investments in leveraged leases;~~holds lease investments; PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) ~~electric~~ transmission and distribution (T&D) system under ~~a contractual~~an Operations ~~and~~ Services ~~Agreement;~~Agreement (OSA); and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.

Our business discussion in ~~Part I,~~ Item 1. Business of our ~~2016~~2022 Annual Report on 10-K (Form 10-K) provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in ~~Part I,~~ Item 1A. Risk Factors of Form 10-K provides information about factors that could have a material adverse impact on our businesses. The following supplements that discussion and the discussion included in the Executive Overview of ~~2016~~2022 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during ~~2017~~2023 and changes to the key factors that we expect may drive our future performance. The following discussion refers to the Condensed Consolidated Financial Statements (Statements) and the Related Notes to Condensed Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements, Notes and the ~~2016~~ Form 10-K.

EXECUTIVE OVERVIEW OF ~~2017~~2023 AND FUTURE OUTLOOK

We are a public utility holding company that, acting through our wholly owned subsidiaries, is a predominantly regulated electric and gas utility and a nuclear generation business. Our business plan ~~is designed~~focuses on achieving growth by allocating capital primarily toward regulated investments in an effort to ~~achieve growth while managing~~continue to improve the ~~risks associated with fluctuating commodity prices~~sustainability and ~~changes in customer demand.~~predictability of our business. We ~~continue~~are focused on investing to modernize our focus on operational excellence, financial strength and disciplined investment. These guiding principles have provided the base from which we have been able to execute our strategic initiatives, including:

i~~mproving utility operations through investment in T&D and other~~energy infrastructure, ~~projects designed to enhance system~~improve reliability and ~~resiliency~~resilience, increase EE and deliver cleaner energy to meet customer expectations and be well aligned with public policy ~~objectives,~~

objectives. In furtherance of these goals, our investments in PSE&G have adjusted our business mix to reflect a higher percentage of earnings contribution by PSE&G. See Item 1. Note 3. Early Plant Retirements/Asset Dispositions and Impairments for additional information. In addition, the passage of the Inflation Reduction Act (IRA) established a Production Tax Credit (PTC) for existing nuclear facilities from 2024 through 2032 which is expected to provide downside price protection for our nuclear generation fleet.

~~maintaining~~PSE&G

At PSE&G, our focus is on investing capital in T&D infrastructure and ~~expanding~~clean energy programs to enhance the reliability and resiliency of our T&D system, meet customer expectations and support public policy objectives. For the years 2023-2027, PSE&G’s capital investment program is estimated to be in a ~~reliable generation fleet with~~range of $15.5 billion to $18 billion, resulting in an expected compound annual growth in rate base of 6% to 7.5% from year-end 2022 to year-end 2027. This represents the ~~flexibility~~majority of PSEG’s total capital investment program of $16.3 billion to ~~utilize~~$18.9 billion. The low end of PSE&G’s range includes an extension of our Gas System Modernization Program (GSMP) and Clean Energy Future (CEF)-EE program at their current average annual investment levels plus inflation, as these programs are expected to continue beyond their currently approved timeframes. The upper end of our capital investment range includes an extension of our Energy Strong program, which otherwise concludes in 2024, as well as the remaining portion of our CEF proposal (portion of Electric Vehicle (EV) and Energy Storage (ES) programs) and a ~~diverse mix~~potentially higher amount of ~~fuels which allows us to respond to market volatility~~investments for GSMP and ~~capitalize on opportunities as they arise.~~

CEF-EE beyond current levels. In May 2023, the

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BPU approved a $280 million nine-month extension of our CEF-EE program through June 2024. We also filed for a three-year extension of GSMP in March 2023 which would provide for continuation of the program. The $2.5 billion proposal provides for acceleration of the replacement of the remaining cast iron and unprotected steel main in our system as well as initiating projects to introduce renewable natural gas and hydrogen blending into our existing distribution system. A remaining component of our CEF-EV program related to medium and heavy duty charging infrastructure has been the subject of a stakeholder process that the BPU began in 2021 and we expect that this effort will result in PSE&G submitting a filing targeting infrastructure investments for the medium and heavy duty EV market in 2023. In September 2022, the BPU released a draft Storage Incentive Program proposal and is currently undertaking a stakeholder process to receive comments. In the meantime, our CEF-ES program is being held in abeyance. Pursuant to our GSMP II and Energy Strong II programs, we are required to file a distribution base rate case no later than December 31, 2023. Among other things, the rate case will recover capital expenditures associated with these programs that are not already in rates, as well as the Advanced Metering Infrastructure and EV programs, other investments that are not recovered through periodic rate roll-ins, and several other cost and return factors. We expect to conclude the case in the second half of 2024.

PSEG Power

At PSEG Power, we seek to produce low-cost electricity by efficiently operating our nuclear generation assets, mitigate volatility by contracting in advance for a significant portion of their output and support public policies that preserve these existing nuclear generating plants. During the first six months of 2023, our nuclear units generated 16.1 terawatt hours and operated at a capacity factor of 95.8%.

More than 90% of PSEG Power’s expected gross margin in 2023 relates to hedged energy margin, known capacity revenues, Zero Emission Certificate (ZEC) revenues and, certain gas operations and ancillary service payments such as reactive power, which limits our exposure to uncontracted market prices. Over the past two years, forward energy prices have demonstrated considerable price volatility. This has led to significant variations in our collateral requirements. As of June 30, 2023, net cash collateral postings were approximately $426 million. While currently off their highs experienced during 2022, collateral postings could remain volatile in the future. PSEG continues to maintain sufficient liquidity as described in Liquidity and Capital Resources.

Climate Strategy and Sustainability Efforts

For more than a century, our purpose has been to provide safe access to an around-the-clock supply of reliable, affordable energy. Today, our vision is to power a future where people use less energy, and it is cleaner, safer and delivered more reliably than ever. We have established a net zero greenhouse gas (GHG) emissions by 2030 goal that includes direct GHG emissions (Scope 1) and indirect GHG emissions from operations (Scope 2) across our business operations, assuming advances in technology, public policy and customer behavior. Scope 1 emissions include power generation, methane leaks, vehicle fleet emissions, and sulfur hexafluoride and refrigerant leaks. Scope 2 emissions include both gas and electric purchased energy for our PSE&G facilities and line losses. We have also committed to the United Nations-backed Race to Zero campaign. Therefore, we continue to evaluate the criteria for science-based emission reduction targets encompassing Scopes 1, 2 and 3 emissions (the majority of which are associated with the downstream use of energy products) in relation to the Science Based Targets initiative (SBTi).

PSE&G has undertaken a number of initiatives that support the reduction of GHG emissions and the implementation of EE initiatives. PSE&G’s approved CEF-EE, CEF-Energy Cloud and CEF-EV programs and the proposed CEF-ES program are intended to support New Jersey’s Energy Master Plan (EMP) through programs designed to help customers increase their EE, support the expansion of the EV infrastructure in the State, install energy storage capacity to supplement solar generation and enhance grid resiliency, install smart meters and supporting infrastructure to allow for the integration of other clean energy technologies and to more efficiently respond to weather and other outage events.

In addition, PSE&G is committed to the safe and reliable delivery of natural gas to approximately 1.9 million customers throughout New Jersey and we are equally committed to reducing GHG emissions associated with such operations. The first phase of our GSMP replaced approximately 450 miles of cast-iron and unprotected steel gas main infrastructure, and the second phase of this program replaced an additional 1,090 miles of gas pipes and was completed in the first quarter of 2023. The GSMP is designed to significantly reduce natural gas leaks in our distribution system, which would reduce the release of methane, a potent GHG, into the air. Through GSMP II, from 2018 through 2023 we reduced methane leaks by approximately 22% system wide and assuming continuation of GSMP, we expect to achieve an overall reduction in methane emissions of at least 60% over the 2011 through 2030 period. We also continue to assess physical risks of climate change and adapt our capital investment program to improve the reliability and resiliency of our system in an environment of increasing frequency and severity of weather events, notably through our investments in our Energy Strong program and Infrastructure Advancement Program and our investments in transmission infrastructure upgrades. These investments have shown benefits in recent severe weather events, including Tropical Storm Ida in 2021, which brought significant flooding to our service territory but did not result in the loss of any of our electric distribution substations.

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We also continue to focus on providing cleaner energy for our customers by working to preserve the economic viability of our nuclear units, which provide over 85% of the carbon-free energy in New Jersey. These efforts include reducing market risk by advocating for state and federal policies, such as the IRA discussed below, that recognize the value of our nuclear fleet’s carbon-free generation and its contribution to grid reliability.

Offshore Wind

In May 2023, PSEG sold to Ørsted North America Inc. (Ørsted) its 25% equity interest in Ocean Wind JV HoldCo, LLC. The sale proceeds approximated PSEG’s carrying value of the investment; therefore, no material gain or loss was recognized upon disposition.

Additionally, PSEG and Ørsted each owns 50% of Garden State Offshore Energy LLC (GSOE) which holds rights to an offshore wind lease area just south of New Jersey.PSEG is evaluating its options for the potential sale of its interest in GSOE.

In April 2023, the BPU issued an order requesting that PJM conduct a second public policy transmission solicitation process utilizing the State Agreement Approach for transmission projects to support New Jersey’s expanded offshore wind goal. This goal, announced in a September 2022 executive order issued by Governor Murphy, is to develop an additional 3.5 gigawatts (GWs) of offshore wind generation, to bring New Jersey’s overall goal to 11 GWs. The solicitation will seek to procure both onshore and offshore transmission solutions. PJM stated that the solicitation process is tentatively expected to commence in 2024.

Financial Results

The results for PSEG, PSE&G and PSEG Power & Other for the three months and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~2022 are presented as follows:



	Three Months Ended				Six Months Ended
	June 30,				June 30,
Earnings (Losses)	2023		2022		2023		2022
	Millions
PSE&G	$	336	$	305	$	823	$	814
PSEG Power & Other (A)	255		(174)		1,055		(685)
PSEG Net Income	$	591	$	131	$	1,878	$	129

PSEG Net Income Per Share (Diluted)	$	1.18	$	0.26	$	3.76	$	0.26

Three Months Ended Nine Months Ended
September 30, September 30,
Earnings (Losses) 2017 2016 2017 2016
Millions
PSE&G $ 246
$ 255
$ 753
$ 696

Power (A) 136
139
(131 ) 320

Other (B) 13
(67 ) (4 ) (31 )
PSEG Net Income $ 395
$ 327
$ 618
$ 985

PSEG Net Income Per Share (Diluted) $ 0.78
$ 0.64
$ 1.22
$ 1.94


~~(A)~~	Includes after-tax expenses of $5 million and $568 million in the three months and nine months ended September 30, 2017, respectively, and after-tax expenses of $67 million for the three months and nine months ended September 30, 2016 related to the early retirement of Power’s Hudson and Mercer coal/gas generation plants. See Item 1. Note 3. Early Plant Retirements for additional information.

~~(B)~~

(A)Other includes after-tax activities at the parent company, PSEG LI, and Energy Holdings as well as intercompany eliminations.

PSEG LI, and Energy Holdings as well as intercompany eliminations. Energy Holdings recorded after-tax charges of $45 million for the nine months ended September 30, 2017, and an after-tax impairment of $86 million for the three months and nine months ended September 30, 2016 related to its investments in NRG REMA, LLC’s (REMA) leveraged leases. See Item 1. Note 6. Financing Receivables for additional information.

Power’s results above include ~~the realized gains, losses and earnings on~~ the Nuclear Decommissioning Trust (NDT) Fund ~~and other related NDT~~ activity and the impacts of non-trading commodity mark-to-market (MTM) activity, which consist of the financial impact from positions with future delivery dates.

The variances in our Net Income ~~include the~~attributable to changes related to the NDT Fund and MTM are shown in the following table:



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2023		2022		2023		2022
	Millions, after tax
NDT Fund Income (Expense) (A) (B)	$	35	$	(117)	$	60	$	(163)
Non-Trading MTM Gains (Losses) (C)	$	212	$	(74)	$	767	$	(682)

Three Months Ended Nine Months Ended
September 30, September 30,
2017 2016 2017 2016
Millions, after tax
NDT Fund Income (Expense) (A) (B) $ 10
$ 2
$ 32
$ (4 )
Non-Trading MTM Gains (Losses) (C) $ (27 ) $ 34
$ —
$ (54 )

(A)NDT Fund Income (Expense) includes gains and losses on NDT securities which are recorded in Net Gains (Losses) on Trust Investments. See Item 1. Note 8. Trust Investments for additional information. NDT Fund Income (Expense) also includes interest and dividend income and other costs related to the NDT Fund recorded in Other Income (Deductions), interest accretion expense on PSEG Power’s nuclear Asset Retirement Obligation (ARO) recorded in Operation and Maintenance (O&M) Expense and the depreciation related to the ARO asset recorded in Depreciation and Amortization (D&A) Expense.

~~(A)~~

NDT Fund Income (Expense) includes the realized gains and losses, interest and dividend income and other costs related to the NDT Fund which are recorded in Other Income and Deductions, and impairments on certain NDT securities recorded as Other-Than-Temporary Impairments. Interest accretion expense on Power’s nuclear Asset Retirement Obligation (ARO) is recorded in Operation and Maintenance (O&M) Expense and the depreciation related to the ARO asset is recorded in Depreciation and Amortization (D&A) Expense.


~~(B)~~	~~Net of tax (expense) benefit of $(12) million, $(2) million, $(37)~~ (B)Net of tax (expense) benefit of $(23) million and ~~$0 million for the three and nine months ended September 30, 2017 and 2016, respectively.~~


~~(C)~~	~~Net of tax (expense) benefit of $19 million $(24) million, $0 million and $37 million for the three and nine months ended September 30, 2017 and 2016, respectively.~~

~~Our~~ $68 million ~~increase in~~for the three months and $(40) million and $94 million for the six months ended June 30, 2023 and 2022, respectively.

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(C)Net of tax (expense) benefit of $(84) million and $30 million for the three months and $(301) million and $267 million for the six months ended June 30, 2023 and 2022, respectively.

Our Net Income for the three months and six months ended ~~September~~June 30, ~~2017 was~~2023 increased as compared to the comparable periods in 2022 driven primarily by

~~an impairment~~•MTM gains in ~~2016 related to investments in certain leveraged leases at Energy Holdings,~~

~~higher charges in 2016 related to early retirement of our Hudson and Mercer coal/gas generation units at Power,~~

~~lower generation costs driven by lower natural gas costs and congestion costs, and~~

~~higher transmission revenues.~~

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~~These favorable variances were partially offset by~~

~~lower sales of electricity sold under the Basic Generation Service contract and in PJM, and~~

~~MTMlossesin 2017~~2023 as compared to MTM losses in 2022 due to changing energy prices,

•unrealized gains in ~~2016.~~

2023 as compared to unrealized losses in 2022 on equity securities in the NDT Fund, and

~~Our $367 million decrease~~•higher earnings due to continued investments in Net Income for the nine months ended September 30, 2017 was driven largely by higher charges, primarily accelerated depreciation, related to the early retirement of our Hudson and Mercer coal/gas generation unitsT&D clause programs at ~~Power. These decreases were~~ PSE&G,

•partially offset by

lower ~~O&M Expense due to cost control efforts,~~

~~lower charges related to investments in certain leveraged leases at Energy Holdings,~~

~~MTM losses in 2016, and~~

~~higher NDT gains and lower NDT losses in 2017.~~

During the first nine months of 2017, we maintained a strong balance sheet. We continued to effectively deploy capital without the need for additional equity, while our solid credit ratings aided our ability to access capital and credit markets. The greater emphasis on capital spending for projects on which we receive contemporaneous returns at PSE&G, our regulated utility, in recent years has yielded strong results, which when combined with the cash flow generated by Power, our merchant generator and power marketer, has allowed us to increase our dividend. These actions to transition our business to meet market conditions and investor expectations reflect our long-term approach to managing our company. Our focus has been to invest capital in T&Dpension and other ~~infrastructure projects aimed at maintaining service reliability to our customers and bolstering our system resiliency. At Power, we strive to improve performance and reduce costs~~postretirement benefit (OPEB) credits in ~~order to enhance the value of our generation fleet in light of low gas prices, environmental considerations and competitive market forces that reward efficiency and reliability.~~

At PSE&G, we continue to invest in transmission projects that focus on reliability improvements and replacement of aging infrastructure, including our $275 million Newark Switch project that was approved by PJM in July 2017. We also continue to make investments to improve the resiliency of our gas and electric distribution system as part of our Energy Strong program that was approved by the BPU in 2014 and to seek recovery on such investments. We also continue to modernize PSE&G’s gas distribution systems as part of our Gas System Modernization Program (GSMP) that was approved by the BPU in late 2015. Over the past few years, these types of investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G.

As a result of our Energy Strong Order from the BPU, we are required to file a distribution base rate case. Following discussions with BPU Staff and Rate Counsel, and as approved by the BPU at its October 20, 2017 meeting, the deadline for filing PSE&G’s distribution base rate case was moved from November 1, 2017 to December 1, 2017. The initial filing will now be based upon three months of actual data and nine months of forecasted data updated for actual data throughout the proceeding. The distribution base rate case will provide PSE&G the opportunity to recover investments made since its last distribution base rate case, including investments that were not recovered through clauses, such as the stipulated base investment associated with GSMP, the portion of Energy Strong investment not recovered through the clause, and investments that exceeded our depreciation levels in revenues. Recovery of these investments, coupled with updates to O&M and other adjustments, are anticipated to result in a proposed mid-single digit percentage increase in PSE&G distribution revenues. The distribution base rate case filing will include a test year through June 30, 2018 and will request the inclusion of known and measurable changes in rate base through December 31, 2018, a 10.3% return on equity (ROE) and a capitalization structure with a 54% equity component, and we expect to request new rates effective October 1, 2018. As part of the filing, we will also request approval to decouple electric and gas revenues from sales volumes for most distribution customer classes. We cannot predict the outcome of this proceeding.

In July 2017, we filed a petition with the BPU for GSMP II, a five-year extension of GSMP, which would accelerate the pace of replacement of our aging cast iron and unprotected steel mains and associated service. We proposed to invest up to $540 million per year over this five-year program beginning in 2019. In August 2017, the BPU approved our request for an extension of our Energy Efficiency program.

Although the weather in the first three months of 2017 was warmer than normal, Power’s results saw a continuing benefit from access to natural gas supplies through existing firm pipeline transportation contracts. Power manages these contracts for the benefit of PSE&G’s customers through the basic gas supply (BGSS) arrangement. The contracts are sized to provide for delivery of a reliable gas supply to PSE&G customers on peak winter demand days. When pipeline capacity beyond the customers’ needs is available, Power can use it to make third-party sales and if excess volume remains after the third-party sales, supply gas to its generating units in New Jersey. Alternatively, gas supply and pipeline capacity constraints could adversely impact our ability to meet the needs of our utility customers and generating units.

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Power’s hedging practices and ability to capitalize on market opportunities help us to balance some of the volatility of the merchant power business. Power’s hedging program in combination with expected revenues from the capacity market mechanisms and certain ancillary service payments, such as reactive power, has secured approximately 60% of its estimated gross margin for the 2017-2019 period.

Our investments in Keys Energy Center (Keys), Sewaren 7 and Bridgeport Harbor Station unit 5 (BH5) reflect our recognition of the value of opportunistic growth in the Power business. These highly efficient additions to our fleet both expand our geographic diversity and adjust our fuel mix and are expected to improve our financial performance.

Since 2013, several nuclear generating stations in the United States have closed or announced early retirement due to economic reasons, or have announced as being at risk for early retirement. This situation is generally due to the decline in market prices of energy, resulting from low natural gas prices driven by the growth of shale gas production since 2007, the continuing cost of regulatory compliance and enhanced security for nuclear facilities and both federal and state-level policies that provide financial incentives to renewable energy such as wind and solar, but generally do not apply to nuclear generating stations. These trends have significantly reduced the revenues of nuclear generating stations while limiting their ability to reduce the unit cost of production. This may result in the electric generation industry experiencing a shift from nuclear generation to natural gas-fired generation, creating less diversity of the generation fleet.

If the market trends noted above continue or worsen, our New Jersey nuclear generating units could cease being economically competitive, which may cause us to retire such units prior to the end of their useful lives. The costs associated with any such potential retirement, which may include, among other things, accelerated D&A or impairment charges, accelerated asset retirement costs, severance costs, environmental remediation costs, and additional funding of NDT funds would likely have a material adverse impact on future financial results. We continue to advocate for sound policies that recognize nuclear power as a source of reliable and clean energy, free of air emissions and an important part of a diverse and reliable energy portfolio. See Item 1. Note 3. Early Plant Retirements for additional information.

In addition, a number of states have either taken action or are investigating the situation faced by nuclear generating units. Recently, courts in Illinois and New York upheld challenges to the programs which established zero emissions credits, recognizing the importance of nuclear units for providing clean energy, free of air emissions.

In September 2017, the Secretary of the U.S. Department of Energy (DOE) issued a Notice of Proposed Rulemaking (NOPR) directing FERC to act within 60 days to develop a mechanism that would allow for the recovery of costs of fuel-secure generation units such as nuclear and coal. To be eligible for compensation under the NOPR, units must be able to provide certain essentialenergy and ancillary reliability services, have a 90-day fuel supply on site and not subject to cost-of-service rate regulation by any State or local authority. PSEG is evaluating the potential effects this NOPR could have on its generating fleet. PSEG filed comments in support of the DOE’s NOPR and contended that it should be implemented immediately as an interim measure to prevent the premature retirement of fuel-secure baseload units. PSEG also requested that FERC direct the regional transmission organizations (RTOs) to work with stakeholders to develop a long-term market-based methodology for valuing resiliency in the generator fleet. Additionally, PSEG argued that FERC should expedite the implementation of pending price formation reforms, including fast-start pricing and uplift allocation and market transparency. Finally, PSEG requested that FERC direct PJM to file its proposal that would allow baseload units to set the locational marginal prices during low load conditions. We cannot predict the outcome of this matter.2023.

Regulatory, Legislative and Other Developments

~~In our pursuit of operational excellence, financial strength and disciplined investment, we~~We closely monitor and engage with stakeholders on significant regulatory and legislative developments. Transmission planning rules and wholesale power market design are of particular importance to our results and we continue to advocate for policies and rules that promote fair and efficient electricity markets.

~~Transmission~~

In April 2017, the PJM Board announced that it would be lifting the previously disclosed suspension of the Artificial Island transmission project and approved the award to PSE&G of the construction of necessary upgrade work at a cost of approximately $130 million. Also, in April 2017, PJM submitted a proposal to FERC concerning the cost responsibility assigned to certain entities, including PSE&G, for the Artificial Island project. In October 2017, FERC accepted PJM’s filing on the grounds that PJM correctly applied its Tariff, but deferred any further ruling on whether the cost allocation methodology applied to the Artificial Island project is appropriate. FERC will decide this issue in a separate proceeding that is currently pending before it.

There are several matters pending before FERC and the U. S. Court of Appeals for the District of Columbia Circuit that concern the allocation of costs associated with transmission projects being constructed by PSE&G. Regardless of how these proceedings are resolved, PSE&G’s ability to recover the costs of these projects will not be affected. However, the result of these proceedings could ultimately impact the amount of costs borne by ratepayers in New Jersey. In addition, as a basic generation

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service (BGS) supplier, Power provides services that include specified transmission costs. If the allocation of the costs associated with the transmission projects were to increase these BGS-related transmission costs, BGS suppliers may be entitled to recovery, subject to BPU approval. We do not believe that these matters will have a material effect on Power’s business or results of operations.

Several complaints have been filed and several remain pending at FERC against transmission owners around the country, challenging those transmission owners’ base return on equity (ROE). Certain of those complaints have resulted in decisions and others have been settled, resulting in reductions of those transmission owners’ base ROEs. The results of these other proceedings could set precedents for other transmission owners with formula rates in place, including PSE&G.

Wholesale Power Market Design

~~Capacity~~In February 2023, FERC issued an order accepting PJM’s proposal to recalculate the market ~~design, including the Reliability Pricing Model (RPM) in PJM, remains an important focus~~clearing price for ~~us. During 2015, PJM implemented a new “Capacity Performance” (CP) mechanism that created a more robust~~one particular capacity ~~product with enhanced incentives for performance during emergency conditions and significant penalties for non-performance. The CP product was implemented fully in the May 2017 RPM auction~~zone for the ~~2020-2021 Delivery Year. Subsequent~~December 2022 Base Residual Auction. FERC also accepted PJM’s tariff revisions to ~~its implementation,~~allow it to implement similar changes in future auctions. A number of parties have appealed the FERC ~~approved changes~~Order to the ~~CP construct that will enhance the participation~~D.C. Circuit Court of ~~intermittent~~Appeals and demand response resources (seasonal resources). However, two complaints remain pending that ask FERC to investigate the rules governing the participation of seasonal resources and extend the participation of the base resources for future auctions.

In May 2017, PJM announced the results of the RPM capacity auction for the 2020-2021 delivery year. Power cleared approximately 7,800 MW of its generating capacity at an average price of $174 per MW-day for the 2020-2021 delivery period. In the two prior capacity auctions covering the 2019-2020 and 2018-2019 delivery years, Power cleared approximately 8,900 MW at an average price of $116 and approximately 8,700 MW at an average price of $215 per MW-day, respectively. Prices in the most recent auction reflect PJM’s downwardly-revised demand forecast, changes in the emergency transfer limits due to transmission expansion and the effects of both the new generation and uncleared generation from the prior year’s auction.

As a result of the efforts of certain entities in PJM to obtain financial support arrangements from their state commissions, a group of suppliers requested that FERC direct PJM to expand the currently effective “minimum offer price rule” to apply to certain existing units seeking subsidies. The suppliers’ request was intended to avoid a scenario where the subsidized generators would submit bids into the PJM capacity market that did not reflect their actual costs of operation and could artificially suppress capacity market prices. We are currently awaiting FERC action on the suppliers’ request andwe cannot predict the ~~outcome of~~outcome.

Transmission Rate Proceedings and Return on Equity (ROE)

Under current FERC rules, PSE&G continues to earn a 50 basis point adder to its base ROE for its membership in PJM as a transmission owner. In April 2021, FERC proposed eliminating this ROE adder for Regional Transmission Owner participation. FERC has not acted on the ~~proceeding.~~proposal. If the adder was eliminated it would reduce PSE&G’s annual Net Income and annual cash inflows by approximately $30 million to $40 million.

New Jersey Stakeholder Proceedings

In ~~June 2017, PJM~~February 2023, New Jersey Governor Murphy issued anexecutive orders (EOs) that establish or accelerate previously established 2050 targets for clean-sourced energy, ~~price formation proposal~~building electrification, and EV adoption goals, with new target dates of 2030 or 2035, as applicable. The EOs direct the BPU and other state agencies to ~~address~~collaborate with stakeholders to develop plans to reach the targets and convene a ~~flaw in~~stakeholder proceeding to develop a plan for gas distribution utilities to reach the ~~energy market in which energy prices during off-peak periods often do not reflect the production costs~~target of ~~generators during these periods even though they~~50% natural gas emissions reductions over 2006 levels by 2030. We are ~~serving load. PJM’s proposal would allow large, inflexible units~~unable to ~~set price. If placed into effect, this proposal will improve price formation by ensuring that the marginal costs of units serving load will be better reflected in clearing prices. We cannot~~ predict the ~~outcome~~outcomes of this ~~matter.~~

~~Distribution~~

~~In June 2017, the BPU issued proposed Infrastructure Investment Program (IIP) regulations that would allow utilities to construct, install, or remediate utility plant~~proceeding, but it could have a material impact on our business, results of operations and facilities related to reliability, resiliency, and/or safety to support the provision of safe and adequate service. Under the proposed regulations, utilities could seek authority to make specified infrastructure investments in programs extending for up to five years with accelerated cost recovery mechanisms. The BPU characterized the IIP regulations as a regulatory initiative intended to create a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing infrastructure that enhances reliability, resiliency, and/or safety. The proposed regulations will be subject to comment from interested parties.cash flows.

Environmental Regulation

We continue to advocate for the development and implementation of fair and reasonable rules by the EPA and state environmental regulators. In particular, section 316(b) of the Federal Water Pollution Control Act requires that cooling water intake structures, which are a significant part of the generation of electricity at steam-electric generating stations, reflect the best technology available for minimizing adverse environmental impacts. Implementation of Section 316(b) and related state regulations could adversely impact future nuclear and fossil operations and costs.

~~In March 2017, the President of the United States issued an Executive Order that instructed the EPA to review the New Source Performance Standards, which establish emissions standards for CO~~₂ for certain new fossil power plants, and the Clean Power Plan (CPP), a greenhouse gas emissions regulation under the Clean Air Act for existing power plants that establishes state-specific emission rate targets based on implementation of the best system of emission reduction. In October 2017, the EPA Administrator signed a proposed repeal of the CPP. The Administrator concluded that the CPP exceeds the EPA’s statutory authority by considering measures that are beyond the control of the owners of the affected sources (fossil fuel-fired electric

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generating units). Whether the EPA chooses to propose a replacement rule has not been decided. PSEG cannot estimate the impact of these actions on our business and future results of operations at this time.

We are subject to liability under environmental laws for the costs and penalties of remediating ~~environmental~~ contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we generated. In particular, the historic operations of PSEG companies and the operations of numerous other companies along the Passaic and Hackensack Rivers are alleged by ~~Federal~~federal and ~~State~~state agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of variousstatutes. In addition, PSEG Power has retained ownership of certain liabilities excluded from the sale of its fossil generation portfolio, primarily related to obligations under New Jersey and Connecticut state law to investigate and remediate the sites. We are also currently involved in a number of proceedings relating to sites where other hazardous substances may have been discharged and may be subject to additional proceedings in the future, and the costs and penalties of any such remediation efforts could be material.

For further information regarding the matters described above, as well as other matters that may impact our financial condition and results of operations, see Item 1. Note ~~9. Commitments and Contingent Liabilities~~.

~~FERC Compliance~~

Since September 2014, FERC Staff has been conducting a preliminary non-public investigation regarding errors in the calculation of certain components of Power’s cost-based bids for its New Jersey fossil generating units in the PJM energy market and the quantity of energy that Power offered into the energy market for its fossil peaking units compared to the amounts for which Power was compensated in the capacity market for those units. While considerable uncertainty remains as to the final resolution of these matters, based upon developments in the investigation in the first quarter of 2017, Power believes the disgorgement and interest costs related to the cost-based bidding matter may range between approximately $35 million and $135 million, depending on the legal interpretation of the principles under the PJM Tariff, plus penalties. Since no point within this range is more likely than any other, Power has accrued the low end of this range of $35 million by recording an additional pre-tax charge to income of $10 million during the three months ended March 31, 2017. PSEG is unable to reasonably estimate the range of possible loss, if any, for the quantity of energy offered matter or the penalties that FERC would impose relating to either the cost-based bidding or quantity of energy matter. However, any of these amounts could be individually material to PSEG and Power. We cannot predict the final outcome of these matters. For additional information, see Item 1. Note 9.10. Commitments and Contingent Liabilities.

~~Early Retirement~~Nuclear

In April 2021, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs for the three-year eligibility period starting June 2022 at the same approximate $10 per megawatt hour (MWh) received during the prior ZEC period through May 2022. Pursuant to a process established by the BPU, ZECs are purchased from selected nuclear plants and recovered through a non-bypassable distribution charge in the amount of ~~Hudson~~$0.004 per kilowatt-hour used (which is equivalent to approximately $10 per MWh generated in payments to selected nuclear plants (ZEC payment)). As previously noted, in August 2022, the IRA was signed into law expanding incentives promoting carbon-free generation. The enacted legislation established the PTC for electricity generation using existing nuclear energy set to begin in 2024 through 2032. The expected PTC rate is up to $15/MWh subject to adjustment based upon a facility’s gross receipts. The PTC rate and ~~Mercer Units~~

~~On June 1, 2017, Power completed its previously announced retirement~~the gross receipts cap are subject to annual inflation adjustments. We are continuing to analyze the impact of the ~~generation operations~~IRA on our nuclear units, including future guidance from the U.S. Treasury and the impact of ~~the existing coal/gas units at the Hudson and Mercer generating stations. The decision to retire the Hudson and Mercer units had a material effect~~PTCs on PSEG’s and Power’s results of operations in 2016 and continued to adversely impact their results of operations in 2017. As of June 1, 2017, Power completed recognition of the incremental D&A of $938 million ($964 million in total) due to the significant shortening of the expected economic useful lives of Hudson and Mercer. During the first nine months of 2017, Energy Costs of $10 million and O&M of $12 million were also incurred and other costs may be incurred during the remaining period in 2017.ZEC payments. See Item 1. Note 3. Early Plant ~~Retirements~~Retirements/Asset Dispositions and Impairments for additional information.

~~Power currently anticipates using~~

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Current Inflationary Environment

The current inflationary environment has prompted the ~~sites~~Federal Reserve to tighten monetary policy resulting in higher interest rates, which have impacted financial markets, reducing the value of fixed income investments and created uncertainty about the future economic outlook weakening equity markets. These factors resulted in negative returns on our pension assets during 2022, which resulted in materially higher pension costs in 2023 and are expected to have impacts on future years. The higher interest rates translated into a higher discount rate for ~~alternative industrial activity. However, if Power determines not~~our pension obligations, which lowered our pension liability and positively affected our funded ratio, which remains strong.

In February 2023, PSE&G received an accounting order from the BPU authorizing PSE&G to ~~use~~modify its method for calculating the ~~sites for alternative industrial activity, the early retirement~~amortization of the ~~units at such sites would trigger~~net actuarial gain or loss component of pension expense for ratemaking purposes. This order mitigates some of the volatility in earnings and customer rates related to our pension trust performance, and is effective for calendar year 2023 and forward. As a result of this order, PSEG’s 2023 pension expense, net of amounts capitalized, was reduced by $59 million, resulting in a pension credit of $16 million.

On July 31, 2023, PSEG entered into a commitment agreement with The Prudential Insurance Company of America (the Insurer) under which certain PSEG pension plans agreed to purchase a group annuity contract that will transfer to the Insurer approximately $1 billion of the Plans’ defined benefit pension obligations ~~under~~and associated Plan assets related to certain ~~environmental regulations, including possible remediation. The amounts~~pension benefits. See Note 9. Pension and Other Postretirement Benefits (OPEB) for ~~any such remediation are neither currently probable nor estimable but may be material.~~additional information.

~~In addition,~~Further, higher interest rates on borrowings will contribute to higher interest expense on variable rate debt and impact long-term rates on future financing plans. As of June 30, 2023, PSEG ~~and Power continue~~had entered into floating-to-fixed interest rate swaps totaling $900 million in order to ~~monitor their other coal assets, including~~reduce the ~~Keystone and Conemaugh generating stations,~~volatility in interest expense related to ~~assess their economic viability through the end of their designated useful lives and their continued classification as held for use. The precise timing~~a portion of a ~~change~~$1.25 billion variable rate term loan at PSEG Power due March 2025.

Inflation will also result in ~~useful lives may be dependent upon events out~~upward pressure on operating costs and capital spending.

Tax Legislation

Future federal and state tax legislation and clarification of ~~PSEG’s and Power’s control and may impact their ability to operate or maintain certain assets in the future. These generating stations may be impacted by factors such as environmental~~existing legislation co-owner capital requirements and continued depressed wholesale power prices or capacity factors, among other things. Any early retirement or change in the classification as held for use of our remaining coal units maycould have a material ~~adverse~~ impact on our effective tax rate and cash tax position.

The IRA enacted a new 15% corporate alternative minimum tax (CAMT), effective in 2023, a PTC for existing nuclear generation facilities and allows energy tax credits to be transferable. In June 2023, the U.S. Treasury issued proposed regulations on the transferability of certain credits that may affect PSEG’s post 2023 operations, financial condition and cash flows. Many aspects of the IRA remain unclear and in need of further guidance; therefore, we continue to analyze the impact the IRA will have on PSEG’s and ~~Power’s future~~PSE&G’s results of operations, financial ~~results.~~

~~Leveraged Lease Portfolio~~

~~GenOn Energy, Inc. (GenOn), the parent company of REMA,~~condition and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code on June 14, 2017. REMA was not included in the GenOn bankruptcy filing. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time to complete. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s efforts to restructure its balance sheet and improve its liquidity. We continue to monitor the restructuring of GenOn and the possible related impact on REMA and continue to discuss the situation with GenOn.

During the first quarter of 2017, due to continuing liquidity issues facing REMA, economic challenges facing coal generation in PJM, and based upon an ongoing review of available alternatives as well as discussions with REMA management, Energy Holdings recorded an additional $55 million pre-tax charge for its current best estimate of loss relating to its REMA leveraged

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lease receivables, which was reflected in Operating Revenues. During the second quarter of 2017, Energy Holdings recorded an additional $22 million pre-tax charge for its current best estimate of loss related to lease receivables due to collectability of payments ($15 million) and economics impacting the residual value ($7 million) of certain leased assets. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments,cash flows, which could include further write-downs of the values of Energy Holdings’ leveraged lease receivables. For additional information, see Item 1. Note 6. Financing Receivables. There can be no assurance that a continuation or worsening of the adverse economic conditions would not lead to additional write-downs at any of our other generation units in our leveraged lease portfolio, and such write-downs could be material.

Additional facilities in our leveraged lease portfolio include the Joliet and Powerton generating facilities. Similar to Shawville, Joliet was recently converted to use natural gas. Converted natural gas units such as Shawville and Joliet may have higher operating costs and fuel consumption as well as longer start-up times compared to newer combined cycle gas units. Powerton is a coal-fired generating facility in Illinois. Each of these three facilities may not be as economically competitive as newer combined cycle gas units and could continue to be adversely impacted by the same economic conditions experienced by other less efficient natural gas and coal generation facilities, which could require Energy Holdings to write down the residual value of the leveraged lease receivables associated with these facilities.

~~Salem~~

Concurrently with the planned refueling outage at the Salem 2 unit that was conducted in the second quarter of 2017, we inspected and replaced baffle bolts as part of our strategy to replace baffle bolts at the Salem station.~~The unit was returned to service in June 2017.~~

~~Operational Excellence~~

We emphasize operational performance, exercising diligence in managing costs, while developing opportunities in both our competitive and regulated businesses. Flexibility in our generating fleet has allowed us to take advantage of opportunities in a rapidly evolving market. For the first nine months of 2017, our

~~utility continued top decile performance in electric reliability,~~

~~total nuclear fleet achieved an average capacity factor of 95%,~~

~~diverse fuel mix and dispatch flexibility allowed us to generate approximately 39 terawatt hours, and~~

~~combined cycle fleet produced 11 terawatt hours at an equivalent availability factor of 94%.~~

~~Financial Strength~~

Our financial strength is predicated on a solid balance sheet, positive operating cash flow and reasonable risk-adjusted returns on increased investment. Our financial position remained strong during the first nine months of 2017 as we

~~maintained sufficient liquidity,~~

~~maintained solid investment grade credit ratings, and~~

~~increased our indicative annual dividend for 2017 to $1.72 per share.~~

~~We expect to be able to fund our planned capital requirements without the issuance of new equity.~~

~~Disciplined Investment~~

We utilize rigorous investment criteria when deploying capital and seek to invest in areas that complement our existing business and provide reasonable risk-adjusted returns. These areas include upgrading our energy infrastructure, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. In the first nine months of 2017, we

~~made additional investments in transmission infrastructure projects,~~

~~continued to execute our BPU-approved utility programs, and~~

~~continued construction of our Keys and Sewaren 7 generation projects for targeted commercial operation in 2018 and began construction of BH5 for targeted commercial operations in mid-2019.~~

Future Outlook

Our future success will depend on our ability to continue to maintain strong operational and financial performance ~~in a cost-constrained environment with low gas prices,~~ to capitalize on or otherwise address ~~appropriately~~ regulatory and legislative

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developments that impact our business and to respond to the issues and challenges described below. In order to do this, we ~~must~~will continue to:

~~focus~~•seek approval of and execute on ~~controlling costs while maintaining safety and reliability and complying with applicable standards and requirements,~~

~~successfully manage our energy obligations and re-contract our open supply positions in response to changes in demand,~~

~~successfully launch and grow our retail energy business, which complements our existing wholesale energy business,~~

~~execute~~ our utility capital investment program ~~including our Energy Strong program, GSMP and other investments for growth that yield contemporaneous and reasonable risk-adjusted returns, while enhancing the resiliency of~~to modernize our infrastructure, ~~and maintaining~~improve the reliability and resilience of the service we provide to our customers, and align our sustainability and climate goals with New Jersey’s energy policy,

~~effectively~~ •seek a fair return for our T&D investments through our transmission formula rate, existing rate incentives, distribution infrastructure and clean energy investment programs and periodic distribution base rate case proceedings,

•focus on controlling costs while maintaining safety, reliability and customer satisfaction and complying with applicable standards and requirements,

•manage ~~construction~~the risks and ~~start-up~~opportunities in federal and state clean energy policies, which is an integral part of our ~~Keys, Sewaren 7, BH5~~long-term strategy,

•successfully manage our obligations and ~~other generation projects,~~re-contract our open positions in response to changes in prices and demand,

•advocate for ~~measures~~appropriate regulatory guidance on the federal nuclear PTC to ensure ~~the implementation by PJM~~long-term support for New Jersey’s largest carbon-free generation resource, and ~~FERC~~adapt our hedging program accordingly,

Table of ~~market design and transmission planning rules that continue to promote fair and efficient electricity markets,~~Contents

•engage constructively with our multiple stakeholders, including regulators, government officials, customers, employees, investors, suppliers and ~~investors,~~the communities in which we do business, and

~~successfully operate~~•deliver on our human capital management strategy to attract, develop and retain a diverse, high-performing workforce.

In addition to the ~~LIPA T&D system~~risks described elsewhere in this Form 10-Q and ~~manage LIPA’s fuel supply and generation dispatch obligations.~~

~~For 2017~~in our Form 10-K, for 2023 and beyond, the key issues ~~challenges~~ and ~~opportunities~~challenges we expect our business to confront include:

•regulatory and political uncertainty, both with regard to transmission planning and rates policy, the role of distribution utilities and decarbonization impacts, future energy policy, design of energy and capacity markets, ~~transmission policy~~ and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other ~~proceeding, settlement, investigation or claim, applicable to~~proceedings,

•the current inflationary environment and associated volatility in the financial markets, including the impact on our pension fund performance and interest rates on our future financing plans,

•increases in commodity prices and customer rates, which may adversely affect customer collections and future regulatory proceedings,

•the increasing frequency, sophistication and magnitude of cybersecurity attacks against us and our respective vendors and business partners who may have our sensitive information and/or ~~the energy industry,~~

~~fair and timely rate relief from the BPU and FERC for recovery of costs and return on investments, including with respect~~access to our ~~distribution base rate case proceeding to be filed in 2017,~~environment, and the increasing frequency and magnitude of physical attacks on electric and gas infrastructure,

~~the potential for comprehensive tax reform, particularly in light of public statements by the current U.S. administration and key members of Congress,~~

~~uncertainty in the national and regional economic performance, continuing customer conservation efforts,~~•future changes in ~~energy usage patterns~~federal and ~~evolving technologies, which~~state tax laws or any other associated tax guidance, and

•the impact ~~customer behaviors and demand,~~

~~the potential for continued reductions~~of changes in demand, ~~and sustained lower~~ natural gas and electricity prices, ~~both at market hubs~~ and expanded efforts to decarbonize several sectors of the ~~locations where we operate,~~economy.

the impact of lower natural gas prices and increasing environmental compliance costs on the competitiveness of our nuclear and remaining coal-fired generation plants, and the potential for retirement of such plants earlier than their current useful lives,

~~ensuring timely completion of construction of our T&D, generation and other development projects, including obtaining required permits and regulatory approvals,~~

~~maintaining a diverse mix of fuels to mitigate risks associated with fuel price volatility and market demand cycles, and~~

~~FERC Staff’s continuing investigation of certain of Power’s New Jersey fossil generating unit bids in the PJM energy market.~~

~~Our primary investment opportunities are in two areas: our regulated utility business and our merchant power business.~~ We continually assess a broad range of strategic options to maximize long-term ~~stockholder value. In assessing~~shareholder value and address the interests of our ~~options, we~~multiple stakeholders. We consider a wide variety of factors when determining how and when to efficiently deploy capital, including the performance and prospects of our businesses; returns and the sustainability and predictability of future earnings streams; the views of investors, regulators, public policy initiatives, rating agencies, customers and ~~rating agencies;~~employees; our existing indebtedness and restrictions it imposes; and tax considerations, among other things. Strategic options available to us include:

•investments in PSE&G, including T&D facilities to enhance reliability, resiliency and modernize the ~~acquisition, construction or disposition~~system to meet the growing needs and increasingly higher expectations of ~~transmission~~customers, and ~~distribution facilities and/or generation units,~~clean energy investments such as CEF-EE, CEF-EV, CEF-ES and Solar,

~~the disposition or reorganization~~•continued operation of our ~~merchant~~nuclear generation ~~business or other existing businesses or~~facilities that are supported through the ~~acquisition or development of new businesses,~~PTC through 2032 and can enable certain enhancements to the units as well as potential license extensions,

~~the expansion of our geographic footprint,~~

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~~continued or expanded participation in solar, energy efficiency and related programs, and~~

•investments in ~~capital improvements~~competitive, regulated transmission investments through PJM processes and ~~additions, including the installation of environmental upgrades~~BPU solicitations related to enabling offshore wind that provide revenue predictability and ~~retrofits, improvements~~reasonable risk-adjusted returns, and

•acquisitions, dispositions, developmentand other transactions involving our common stock, assets or businesses that could provide value to ~~system resiliency, modernizing existing infrastructure~~customers and ~~participation in transmission projects through FERC’s “open window” solicitation process.~~shareholders.

There can be no assurance, however, that we will successfully develop and execute any of the strategic options noted above, or any additional options we may consider in the future. The execution of any such strategic plan may not have the expected benefits or may have unexpected adverse consequences.

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RESULTS OF OPERATIONS

PSEG

Our results of operations are ~~primarily~~ comprised of the results of operations of our ~~principal operating subsidiaries,~~reportable segments, PSE&G and PSEG Power & Other, excluding charges related to intercompany transactions, which are eliminated in consolidation. For additional information on intercompany transactions, see Item 1. Note ~~18.~~19. Related-Party Transactions.

Three Months Ended
Increase/
(Decrease)
Nine Months Ended
Increase/
(Decrease)

September 30, September 30,
2017 2016 2017 vs. 2016 2017 2016 2017 vs. 2016
Millions Millions % Millions Millions %
Operating Revenues $ 2,263
$ 2,450
$ (187 ) (8 ) $ 6,988
$ 6,971
$ 17
—

Energy Costs 638
866
(228 ) (26 ) 2,100
2,326
(226 ) (10 )
Operation and Maintenance 680
776
(96 ) (12 ) 2,100
2,215
(115 ) (5 )
Depreciation and Amortization 252
231
21
9
1,721
679
1,042
N/A

Income from Equity Method Investments 3
3
—
—
11
9
2
22

Other Income (Deductions) 56
39
17
44
178
100
78
78

Other-Than-Temporary Impairments 5
5
—
—
9
25
(16 ) (64 )
Interest Expense 100
99
1
1
289
288
1
—

Income Tax Expense 252
188
64
34
340
562
(222 ) (40 )



	Three Months Ended				Increase/ (Decrease)			Six Months Ended				Increase/ (Decrease)
	June 30,							June 30,
	2023		2022		2023 vs. 2022			2023		2022		2023 vs. 2022
	Millions				Millions		%	Millions				Millions		%
Operating Revenues	$	2,421	$	2,076	$	345	17	$	6,176	$	4,389	$	1,787	41
Energy Costs	604		765		(161)		(21)	1,686		2,010		(324)		(16)
Operation and Maintenance	744		751		(7)		(1)	1,487		1,545		(58)		(4)
Depreciation and Amortization	279		269		10		4	561		552		9		2
(Gains) Losses on Asset Dispositions and Impairments	—		(5)		5		N/A	—		38		(38)		N/A
Income from Equity Method Investments	—		7		(7)		N/A	1		11		(10)		(91)
Net Gains (Losses) on Trust Investments	57		(187)		244		N/A	103		(255)		358		N/A
Other Income (Deductions)	49		38		11		29	91		43		48		N/A
Net Non-Operating Pension and OPEB Credits (Costs)	29		94		(65)		(69)	57		188		(131)		(70)
Interest Expense	185		150		35		23	365		287		78		27
Income Tax Expense (Benefit)	153		(33)		186		N/A	451		(185)		636		N/A

The following discussions for PSE&G and PSEG Power & Other provide a detailed explanation of their respective variances.

PSE&G



	Three Months Ended				Increase/ (Decrease)			Six Months Ended				Increase/ (Decrease)
	June 30,							June 30,
	2023		2022		2023 vs. 2022			2023		2022		2023 vs. 2022
	Millions				Millions		%	Millions				Millions		%
Operating Revenues	$	1,662	$	1,668	$	(6)	—	$	3,955	$	3,952	$	3	—
Energy Costs	551		630		(79)		(13)	1,535		1,598		(63)		(4)
Operation and Maintenance	429		434		(5)		(1)	889		897		(8)		(1)
Depreciation and Amortization	240		227		13		6	484		468		16		3
Net Gains (Losses) on Trust Investments	—		(2)		2		N/A	—		(2)		2		N/A
Other Income (Deductions)	23		22		1		5	44		41		3		7
Net Non-Operating Pension and OPEB Credits (Costs)	28		71		(43)		(61)	56		141		(85)		(60)
Interest Expense	123		107		16		15	236		210		26		12
Income Tax Expense (Benefit)	34		56		(22)		(39)	88		145		(57)		(39)

Three Months Ended
Increase/
(Decrease)
Nine Months Ended
Increase/
(Decrease)

September 30, September 30,
2017 2016 2017 vs. 2016 2017 2016 2017 vs. 2016
Millions Millions % Millions Millions %
Operating Revenues $ 1,509
$ 1,684
$ (175 ) (10 ) $ 4,689
$ 4,746
$ (57 ) (1 )
Energy Costs 535
721
(186 ) (26 ) 1,760
1,979
(219 ) (11 )
Operation and Maintenance 346
376
(30 ) (8 ) 1,064
1,110
(46 ) (4 )
Depreciation and Amortization 169
137
32
23
506
412
94
23

Other Income (Deductions) 22
21
1
5
67
58
9
16

Interest Expense 79
72
7
10
223
214
9
4

Income Tax Expense 156
144
12
8
450
393
57
15

Three Months Ended ~~September~~June 30, ~~2017~~2023 as Compared to ~~2016~~Three Months Ended June 30, 2022

Operating Revenues decreased ~~$175~~$6 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenues increased $57 million due primarily to

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~~Delivery Revenues~~ ~~increased $10~~•Transmission revenues were $32 million higher due primarily to an increase in ~~transmission revenues.~~

~~Transmission revenues were $34 million higher due~~revenue requirements attributable to higher ~~revenue requirements calculated through our transmission formula~~ rate ~~primarily to recover required investments.~~base investment.

~~Gas~~•Electric and gas distribution revenues increased $5$25 million due primarily to increases of $31 million from Conservation Incentive Program (CIP) decoupling, $10 million from GSMP II and Energy Strong II collections, and $12 million due to a ~~$1 million increase~~reduction in the flowback to customers of excess deferred tax liabilities and tax repair-related accumulated deferred income tax benefits resulting from ~~the inclusion of Energy Strong~~rate reductions, which is offset in ~~base rates, and $1 million~~Income Tax Expense. These increases ~~in both GSMP collections and Green Program Recovery Charges (GPRC) and higher sales volumes.~~

~~Electric distribution revenues decreased $29 million due to a $38 million decrease due to~~were partially offset by lower sales volumes ~~and lower GPRC~~ of ~~$6 million, partially offset by a $15 million increase from the inclusion of Energy Strong in base rates.~~$27 million.

Commodity ~~Revenue~~Revenues decreased ~~$186~~$86 million as a result of lower Electric and Gas revenues. The changes in Commodity ~~revenue~~revenues for both electric and gas are entirely offset by the changes in Energy Costs. PSE&G earns no margin on the provision of ~~BGS~~basic generation service (BGS) and BGSS to retail customers.

•Electric commodity revenues decreased ~~$176~~$47 million due primarily to $30 million in lower BGS prices and $17 million in lower sales volumes.

•Gas commodity revenues decreased $39 million due primarily to $23 million from lower BGSS prices and $13 million from lower BGSS sales volumes.

Clause Revenues increased $14 million due primarily to a ~~$153~~$17 million ~~decrease~~increase in ~~BGS revenues due to $97 million in lower sales volumes and $56 million from lower prices and $23 million of lower revenues from collections of Non-Utility Generation Charges (NGC).~~

~~Gas commodity revenues decreased $10 million due to lower BGSS sales prices of $22 million, partially offset by higher BGSS sales volumes of $12 million.~~

~~Clause Revenues~~ ~~increased $1 million due primarily to the return of $20 million to customers in 2016 of overcollections of Securitization Transition Charges (STC),~~Green Program Recovery Charge (GPRC) deferrals, partially offset by lower Societal Benefit ~~Charges~~Clause (SBC) revenues of ~~$12 million and a $6 million decrease in 2017 in Margin Adjustment Clause (MAC) revenues.~~$3 million. The changes in ~~the STC,~~GPRC deferral amounts and SBC ~~and MAC amounts~~revenues are entirely offset by changes in the amortization of Regulatory Assets and Regulatory Liabilities and related costs in O&M, D&A, Interest and ~~Interest Expense.~~Income Tax Expenses. PSE&G does not earn margin on ~~STC,~~GPRC deferrals or on SBC ~~or MAC collections.~~revenue.

Other Operating ~~Expenses~~

~~Energy Costs~~ ~~decreased $186 million. This is entirely offset by the change in Commodity Revenue.~~

~~Operation and Maintenance~~ decreased $30 million, primarily due to a $17 million reduction in clause-related costs, $6 million in lower appliance service costs, $6 million of lower distribution corrective and preventative maintenance and a $5 million reduction in GPRC related costs, partially offset by a net increase of $4 million in certain operational expenses.

~~Depreciation and Amortization~~Revenues increased ~~$32~~$9 million due primarily to an increase ~~of $19~~from appliance services and a net increase from renewable energy credit (REC) programs. The changes in revenues from REC programs are entirely offset by changes to Energy Costs.

Operating Expenses

Energy Costs decreased $79 million. This is primarily offset by changes in Commodity Revenues and Other Operating Revenues.

Operation and Maintenance decreased $5 million due primarily to $11 million in ~~amortization of Regulatory Assets~~lower Distribution and Transmission expenditures and a ~~$14~~$6 million ~~increase~~reduction in damages, partially offset by increases of $8 million for voluntary severance costs and $6 million for higher clause and renewable expenditures.

Depreciation and Amortization increased $13 million due primarily to increases in depreciation due to ~~additional~~higher plant placed in ~~service.~~service and software amortization.

Net Non-Operating Pension and OPEB Credits (Costs) decreased $43 milliondue primarilyto a $21 million increase in interest cost, a $17 million decrease in the expected return on plan assets and a$16 million decrease in the amortization of net prior service credits, partially offset by an $11 million decrease in the amortization of the net actuarial loss.

Interest Expense increased $7$16 million due primarily to ~~an increase of $5 million due to net~~March 2023 and December 2022 debt ~~issuances in 2016 and 2017 and a $2 million increase in other interest.~~issuances.

Income Tax Expense ~~increased $12~~decreased $22 million due primarily to ~~uncertain~~increased tax ~~positions and plant-related items.~~benefits in the second quarter 2023 from the flowback of excess deferred income tax benefits.

~~Nine~~Six Months Ended ~~September~~June 30, ~~2017~~2023 as Compared to ~~2016~~Six Months Ended June 30, 2022

Operating Revenues ~~decreased $57~~ increased $3 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenues increased ~~$119~~$110 million due primarily to

•Transmission revenues were $56 million higher due primarily to an increase in ~~transmission revenues.~~

~~Transmission revenues were $116 million higher due~~revenue requirements attributable to higher ~~revenue requirements calculated through our transmission formula~~ rate ~~primarily to recover required investments.~~base investment.

~~Gas~~•Electric and gas distribution revenues increased ~~$29~~$54 million due primarily to increases of $69 million from CIP decoupling, $38 million due to a ~~$14~~reduction in the flowback to customers of excess deferred tax liabilities and tax repair-related accumulated deferred income tax benefits resulting from rate reductions, which is offset in Income Tax Expense, and $33 million ~~increase due to the inclusion of~~in GSMP II and Energy Strong ~~in base rates, $8 million in higher Weather Normalization Clause (WNC) revenue, a $7 million increase due to the GSMP and higher GPRC of $3 million,~~II collections. These increases were partially offset by ~~$3 million of lower delivery volumes.~~

~~Electric distribution revenues decreased $26 million due to a $36 million decrease due to~~ lower sales volumes of $80 million and $5 million in lower GPRC ~~of $14 million, partially offset by a $24 million increase due to the inclusion of Energy Strong in base rates.~~collections.

Commodity ~~Revenue~~Revenues decreased ~~$219~~$76 million as a result of lower Gas and Electric ~~revenues partially offset by higher Gas~~ revenues. The changes in Commodity ~~revenue~~revenues for both ~~electric~~gas and ~~gas~~electric are entirely offset by the changes in Energy Costs. PSE&G earns no margin on the provision of ~~BGS~~BGSS and ~~BGSS~~basic generation service (BGS) to retail customers.

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•Gas commodity revenues decreased $53 million due primarily to $92 million from lower BGSS sales volumes, partially offset by an increase of $39 million from higher BGSS prices.

•Electric commodity revenues decreased ~~$266~~$23 million due to $12 million from lower BGS prices and $11 million from lower sales volumes.

Clause Revenues decreased $49 million due primarily to a ~~$188~~$36 million net decrease in ~~BGS revenues due to $116 million in~~Tax Adjustment Credit (TAC) and GPRC deferrals and lower ~~sales volumes and $72 million of lower prices, $64 million of lower revenues from collections of NGC and a decrease of $14 million due to lower volumes of Non-Utility Generation energy sold.~~

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~~Gas commodity revenues increased $47 million due primarily to $69 million of higher BGSS sales prices, partially offset by $22 million of lower sales volumes.~~

~~Clause Revenues~~ ~~increased $41 million due primarily to the 2016 return to customers of $50 million of overcollections of STC, and higher MAC~~SBC revenues of ~~$2 million in 2017, partially offset by a $12 million decrease in collections of SBC.~~$15 million. The changes in ~~the STC, MAC~~TAC and ~~SBC~~GPRC deferral amounts and Societal Benefit Clause (SBC) revenues are entirely offset by changes in the amortization of Regulatory Assets and Regulatory Liabilities and related costs in O&M, D&A, Interest and ~~Interest Expense.~~Income Tax Expenses. PSE&G does not earn margin on ~~STC, MAC~~TAC and GPRC deferrals or on SBC ~~collections.~~revenue.

Other Operating ~~Expenses~~

~~Energy Costs~~ ~~decreased $219 million. This is entirely offset by the change in Commodity Revenue.~~

~~Operation and Maintenance~~ decreased $46 million, of which the most significant components were decreases of $17 million in distribution corrective and preventative maintenance, $14 million in appliance service costs, $11 million in clause-related costs and $11 million in GPRC costs, partially offset by a $10 million net increase in certain operational expenses.

~~Depreciation and Amortization~~Revenues increased ~~$94~~$18 million due primarily to an increase ~~of $51~~from appliance services and a net increase from REC programs. The changes in revenues from REC programs are entirely offset by changes to Energy Costs.

Operating Expenses

Energy Costs decreased $63 million. This is primarily offset by changes in Commodity Revenues and Other Operating Revenues.

Operation and Maintenance decreased $8 million due primarily to $23 million in ~~amortization~~lower Distribution expenditures and an $8 million reduction in damages, partially offset by increases of ~~Regulatory Assets~~$17 million for voluntary severance costs and ~~a $43~~$9 million ~~increase~~for higher clause and renewable expenditures.

Depreciation and Amortization increased $16 million due primarily to increases in depreciation due to ~~additional~~higher plant placed in ~~service.~~service and software amortization, partially offset by a decrease in the amortization of Regulatory Assets.

Other Income ~~and~~ (Deductions) increased $9$3 million due primarily to an increase ~~of $7~~in investment income.

Net Non-Operating Pension and OPEB Credits (Costs) decreased $85 million ~~in allowance for funds used during construction and~~due primarilyto a $3$42 million increase in ~~realized gains~~interest cost, a $35 million decrease in the expected return on ~~Rabbi Trust investments,~~plan assets and a$31 million decrease in the amortization of net prior service credits, partially offset by a ~~net $1~~$23 million decrease in ~~Solar Loan interest.~~the amortization of the net actuarial loss.

Interest Expense increased $9$26 million due primarily to ~~an increase of $16 million due to net~~March 2023 and March and December 2022 debt ~~issuances in 2016 and 2017, partially offset by a $7 million decrease predominantly driven by a reduction in clause interest.~~issuances.

Income Tax Expense ~~increased~~decreased $57 million due primarily to ~~higher~~lower pre-tax income, increased tax benefits from CEF program investments, the flowback of excess deferred income tax benefits and ~~changes~~flow-through items in ~~uncertain tax positions.~~2023.

~~Power~~

Three Months Ended
Increase/
(Decrease)
Nine Months Ended
Increase/
(Decrease)

September 30, September 30,
2017 2016
2017 vs. 2016 2017 2016 2017 vs. 2016
Millions Millions % Millions Millions %
Operating Revenues $ 873
$ 1,075
$ (202 ) (19 ) $ 3,086
$ 3,102
$ (16 ) (1 )
Energy Costs 357
462
(105 ) (23 ) 1,461
1,481
(20 ) (1 )
Operation and Maintenance 227
289
(62 ) (21 ) 711
807
(96 ) (12 )
Depreciation and Amortization 76
86
(10 ) (12 ) 1,191
245
946
N/A

Income from Equity Method Investments 3
3
—
—
11
9
2
22

Other Income (Deductions) 35
17
18
N/A
105
41
64
N/A

Other-Than-Temporary Impairments 5
5
—
—
9
25
(16 ) (64 )
Interest Expense 12
24
(12 ) (50 ) 41
66
(25 ) (38 )
Income Tax Expense (Benefit) 98
90
8
9
(80 ) 208
(288 ) N/A

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PSEG Power & Other



	Three Months Ended				Increase/ (Decrease)			Six Months Ended				Increase/ (Decrease)
	June 30,							June 30,
	2023		2022		2023 vs. 2022			2023		2022		2023 vs. 2022
	Millions				Millions		%	Millions				Millions		%
Operating Revenues	$	902	$	645	$	257	40	$	2,929	$	1,258	$	1,671	N/A
Energy Costs	196		372		(176)		(47)	859		1,233		(374)		(30)
Operation and Maintenance	315		317		(2)		(1)	598		648		(50)		(8)
Depreciation and Amortization	39		42		(3)		(7)	77		84		(7)		(8)
(Gains) Losses on Asset Dispositions and Impairments	—		(5)		5		N/A	—		38		(38)		N/A
Income from Equity Method Investments	—		7		(7)		N/A	1		11		(10)		(91)
Net Gains (Losses) on Trust Investments	57		(185)		242		N/A	103		(253)		356		N/A
Other Income (Deductions)	27		16		11		69	49		2		47		N/A
Net Non-Operating Pension and OPEB Credits (Costs)	1		23		(22)		(96)	1		47		(46)		(98)
Interest Expense	63		43		20		47	131		77		54		70
Income Tax Expense (Benefit)	119		(89)		208		N/A	363		(330)		693		N/A

Three Months Ended ~~September~~June 30, ~~2017~~2023 as Compared to ~~2016~~Three Months Ended June 30, 2022

Operating Revenues ~~decreased $202~~ increased $257 million due primarily to changes in generation and gas supply and other operating revenues.

Generation Revenues ~~decreased $200~~ increased $445 million due primarily to

•a ~~decrease~~net increase of ~~$110~~$414 million due to MTM ~~losses~~gains in ~~2017~~2023 as compared to MTM ~~gains~~losses in ~~2016.~~2022. Of this amount, ~~$98~~there was a $553 million ~~was~~increase due to changes in forward prices ~~and $12~~in 2023 as compared to 2022, partially offset by a $139 million ~~was~~decrease due to ~~greater gains on~~ positions reclassified to realized upon settlement, ~~this year as compared~~and

•a net increase of $59 million due primarily to ~~last year,~~

~~a decrease of $83 million~~higher average realized prices and volumes sold in ~~electricity sold under our BGS contracts due to lower volumes and lower prices, and~~

~~a decrease of $25 million in energy sales~~2023 in the PJM region, ~~due to lower generation volumes and lower average realized prices,~~

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•partially offset by a net ~~increase~~decrease of ~~$18~~$49 million due primarily to ~~higher capacity revenue and~~lower volumes of electricity sold under ~~wholesale~~the BGS contracts, which ended in May 2023, and other load ~~contracts at higher average prices, coupled with new solar projects.~~contracts.

Gas Supply Revenues decreased $2$189 million due primarily to

•a net decrease of $90 million related to sales to third parties, due primarily to $66 million from lower sales prices, and $24 million from lower sales volumes,

•a net decrease of $82 million in sales under the BGSS contract due primarily to $57 million from lower prices, and $25 million due to lower sales volumes, and

•a net decrease of $17 million due to lower MTM gains in ~~2017~~2023 as compared to ~~2016.~~2022 due primarily to changes in forward prices.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet PSEG Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased ~~$105~~$176 million primarily due to

Gas costs decreased $170 million due mainly to

~~Generation costs~~ ~~decreased $108 million due primarily to~~

•a net decrease of $59 million due to charges associated with the early retirement of the Mercer and Hudson units announced in October 2016, primarily related to a coal inventory write-down, partially offset by additional retirement costs incurred in 2017,

~~a net decrease of $26 million due primarily to lower natural gas costs reflecting lower volumes,~~

~~a net decrease of $11 million primarily due to lower congestion costs in PJM due to lower congestion rates coupled with less congestion volumes, and~~

~~a decrease of $8 million due to MTM gains in 2017 as compared to MTM losses in 2016.~~

~~Gas costs~~ ~~increased $3 million due mainly to a net increase of $2~~$91 million related to sales to third parties, due primarily to $69 million from the lower average cost of ~~which $5 million was due to higher average~~ gas, ~~costs, partially offset by $3~~and $22 million due to lower volumes ~~sold.~~sold, and

~~Operation~~•a net decrease of $78 million related primarily to sales under the BGSS contract, of which $55 million was due to

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lower average cost of gas, and ~~Maintenance~~$23 million due to lower send out volumes.

Income from Equity Method Investments decreased ~~$62~~$7 million due primarily to the sale of our ownership interest in Kalaeloa in May 2023.

~~a $51~~Net Gains (Losses) on Trust Investments increased $242 million ~~decrease at our fossil plants, due to the retirement of the Hudson and Mercer units on June 1, 2017, and~~

~~a $10 million net decrease related to our nuclear plants~~ due primarily to ~~lower labor-related costs.~~NDT investments with $60 million of net unrealized gains on equity securities in 2023 as compared to $170 million of net unrealized losses in 2022 and a decrease of $7 million in net realized losses.

~~Depreciation and Amortization~~ ~~decreased$10~~Other Income (Deductions) increased $11 milliondue primarily to interest income.

~~$19~~Non-Operating Pension and OPEB Credits (Costs) decreased $22 million ~~of lower depreciation~~ due to a decrease in the ~~retirement~~expected return on plan assets, an increase in interest cost, a decrease in the amortization of the ~~Hudson~~net prior service credit and ~~Mercer units,~~

an increase in the amortization of the net actuarial loss, partially offset by $4lower co-owner charges.

Interest Expense increased $20 million ~~of increased depreciation~~ due primarily to the ~~accelerated retirement date~~replacement of maturing debt at ~~Bridgeport Harbor Station unit 3 (BH3),~~the parent company at higher rates, as well as higher rates on PSEG Power and parent company variable rate term loans.

~~$3 million of higher depreciation due to new solar projects, and~~

~~a $2 million increase due to additional nuclear plant placed into service.~~

~~Other~~ Income ~~(Deductions)~~ Tax Expense (Benefit) increased ~~$18~~$208 million due primarily to higher ~~net realized gains~~pre-tax income in ~~the NDT Fund.~~

~~Interest Expense~~ ~~decreased $12 million due primarily to~~

~~a $7 million decrease due to higher interest capitalized for the construction of three new fossil stations: BH5, Sewaren 7~~2023 and ~~Keys, and~~

~~a $5 million decrease due to debt maturities in September 2016.~~

~~Income Tax Expense (Benefit)~~ ~~reflected an~~increased tax expense ~~of $8~~in 2023 on gains from the NDT qualified fund.

Six Months Ended June 30, 2023 as Compared to Six Months Ended June 30, 2022

Operating Revenues increased $1,671 million due primarily ~~to changes in the manufacturing deduction and higher pre-tax income in 2017.~~

~~Nine Months Ended September 30, 2017 as Compared to 2016~~

~~Operating Revenuesdecreased$16 million~~ ~~due~~ to changes in generation and gas supply and other operating revenues.

Generation Revenues ~~decreased $101~~ increased $1,872 million due primarily to

•a net ~~decrease~~increase of ~~$115 million in energy sales in the PJM and New England regions due primarily to lower average realized prices,~~

~~a decrease of $91 million in electricity sold under our BGS contracts due to lower volumes and lower prices,~~

~~a net decrease of $11 million in operating reserves in the PJM region, and~~

~~a charge of $10~~$2,054 million due to ~~an increase~~MTM gains in ~~the FERC reserve accrual related~~2023 as compared to ~~the PJM bidding matter see Item 1. Note 9. Commitments and Contingent Liabilities,~~

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~~partially offset by an increase of $86 million due to lower~~ MTM losses in ~~2017~~2022. Of this amount, there was a $1,746 million increase due to changes in forward prices in 2023 as compared to ~~2016. Of this amount, $110~~2022 coupled with a $308 million ~~was~~increase due to ~~lower gains on~~ positions reclassified to realized upon settlement, ~~this year as compared to last year~~

•partially offset by a net decrease of ~~$24 million due to changes in forward power prices.~~

~~a net increase of $31~~$109 million due primarily to ~~higher~~lower volumes of electricity sold under ~~wholesale~~the BGS contracts, which ended in May 2023, and other load contracts,

•a net decrease of $39 million in capacity revenue due primarily to the sale of the fossil generating plants coupled with lower capacity prices in the NEPJM region, ~~and~~

~~an increase of $10 million~~partially offset by decreases in capacity expenses due to ~~new solar projects.~~lower load volumes served, and

~~Gas Supply Revenuesincreased~~ ~~$84~~•a net decrease of $37 million due primarily to volumes sold in the New England and New York regions in 2022 related to the fossil generating plants sold in February 2022, partially offset by higher average realized prices and volumes sold in 2023 in the PJM region.

~~an increase~~Gas Supply Revenues decreased $207 million due primarily to

•a net decrease of ~~$45~~$123 million related to sales to third parties, primarily due to lower sales prices,

•a net decrease of $44 million in sales under the BGSS contract due primarily to ~~higher average~~$114 million from lower sales ~~prices,~~

~~an increase of $25~~volumes, partially offset by $70 million ~~related to sales to third parties, of which $52 million was~~ due to higher ~~average sales~~ prices, ~~partially offset by $27 million of lower volumes sold,~~ and

•a net ~~increase~~decrease of ~~$14~~$40 million due to MTM ~~gains~~losses in ~~2017~~2023 as compared to MTM ~~losses~~gains in ~~2016.~~2022 primarily due to positions reclassified to realized upon settlement, coupled with changes in forward prices.

Operating Expenses

Generation costs decreased ~~$76~~$226 million due primarily to

•a net decrease of ~~$57~~$191 million in fuel and emission costs due primarily ~~due~~ to ~~lower congestion costs in PJM due to lower congestion rates coupled with less congestion volumes, partially offset by higher transmission charges due to higher rates,~~the sale of the fossil generating plants, and

•a net decrease of ~~$49~~$22 million due to charges associated with the announced early retirement of the Mercer and Hudson units in 2016, primarily related to a coal inventory write-down partially offset by additional retirement costs incurred in 2016,

partially offset by higher fuel costs of $12 million reflecting higher average realized prices for natural gas coupled with the utilization of higher volumes of coal, partially offset by the utilization of lower volumes of gas and oil,

~~a net increase of $10 million primarily due to an increase~~ in energy ~~purchase volumes~~purchases due primarily to lower REC requirements caused by decreases in load served in the ~~NE region to serve load obligations, and~~PJM region.

~~an increase of $9 million due to MTM losses in 2017 as compared to MTM gains in 2016.~~

Gas costs~~increased~~ ~~$56~~ decreased $148 million due mainly to

~~an increase~~•a net decrease of ~~$32 million related to sales under the BGSS contract due to higher average gas costs, and~~

~~an increase of $24~~$115 million related to sales to third parties, primarily due to the lower average cost of gas, and

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•a net decrease of $32 million related primarily to sales under the BGSS contract, of which ~~$48~~$100 million was due to ~~higher average gas costs,~~lower send out volumes, partially offset by ~~a $24~~$68 million ~~decrease in volumes sold.~~due to the higher average cost of gas.

Operation and Maintenance decreased ~~$96~~$50 million ~~due primarily to~~

~~a $71 million decrease at our fossil plants,~~ due primarily to the ~~retirement~~sale of the ~~Hudson~~ fossil generating plants in February 2022.

Losses on Asset Dispositionsand ~~Mercer units and higher planned outage costs in 2016 as compared to 2017,~~

Impairments reflects a ~~$20~~$38 million ~~net decrease related to our nuclear plants~~impairmentloss due primarily to ~~lower labor-related costs~~the sale of the fossil generating plants in February 2022. See Item 1. Note 3. Early Plant Retirements/Asset Dispositions and ~~outage costs, and~~Impairments.

~~an $8~~Income from Equity Method Investments decreased $10 million ~~legal accrual for environmental expenses recorded in 2016,~~

~~partially offset by $3 million of costs related to new solar plants placed into service since September 2016.~~

~~Depreciation and Amortization~~ ~~increased$946 milliondue~~ primarily to

~~$914 million of higher depreciation~~ due to the ~~early retirement~~sale of ~~the Hudson and Mercer units,~~our ownership interest in Kalaeloa in May 2023.

~~$11 million of~~ Net Gains (Losses) on Trust Investments increased ~~depreciation due to the accelerated retirement date at BH3,~~

~~$9 million of higher depreciation due to new solar projects, and~~

~~a $9 million increase due to additional nuclear plant placed into service.~~

~~Other Income (Deductions)~~ ~~increased $64~~$356 million due primarily to ~~$57~~NDT investments with $111 million of ~~higher~~net unrealized gains on equity securities in 2023 as compared to $231 million of net unrealized losses in 2022 and a decrease of $6 million in net realized ~~gains~~losses.

Other Income (Deductions) increased $47 million due primarily to purchases of net operating loss tax benefits under the New Jersey Technology Tax Benefit Transfer Program in ~~the NDT Fund~~2022 and ~~$3 million of~~ higher ~~net realized gains in the Rabbi Trust Fund.~~interest income.

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~~Other-Than-Temporary Impairments~~Non-Operating Pension and OPEB Credits (Costs) decreased ~~$16~~$46 million due to ~~lower impairments of equity securities~~a decrease in the ~~NDT Fund~~expected return on plan assets, an increase in ~~2017.~~interest cost, a decrease in the amortization of the net prior service credit and an increase in the amortization of the net actuarial loss, partially offset by lower co-owner charges.

Interest Expense ~~decreased $25~~ increased $54 million due primarily to the replacement of maturing debt at the parent company at higher rates, the issuance of a PSEG Power term loan in March 2022, as well as higher rates on PSEG Power and parent company variable rate term loans.

~~a $16 million decrease due to higher interest capitalized for the construction of three new fossil stations: BH5, Sewaren 7 and Keys, and~~

~~a net $7 million decrease due to debt maturities in September 2016, partially offset by a debt issuance in June 2016.~~

Income Tax Expense (Benefit) ~~decreased $288~~increased $693 million ~~in 2017~~ due primarily to ~~a pre-tax loss in 2017 as compared to~~higher pre-tax income in ~~2016.~~2023.

LIQUIDITY AND CAPITAL RESOURCES

The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions, where material, of our two direct major operating subsidiaries.

Operating Cash Flows

We continue to expect our operating cash flows combined with cash on hand and financing activities to be sufficient to fund planned capital expenditures and shareholder ~~dividend payments.~~dividends.

For the ~~nine~~six months ended ~~September~~June 30, ~~2017~~,2023, our operating cash flow ~~decreased$27~~increased $2,053 million as compared to the same period in ~~2016.~~2022. The net increase was primarily due to an inflow of $1,095 million in net cash collateral postings in 2023 as compared to a $1,244 million outflow in 2022 at PSEG Power and higher tax payments in 2022, partially offset by a net change ~~was due primarily to net changes from~~at PSE&G, ~~and Power~~ as discussed ~~below as well as net tax payments at PSEG and its other subsidiaries.~~below.

PSE&G

PSE&G’s operating cash flow decreased$8 $769 million from ~~$1,401~~$1,312 million to ~~$1,393~~$543 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~,2023, as compared to the same period in ~~2016~~,2022. The decrease was due primarily to lower ~~tax refunds~~cash collateral postings received from BGS suppliers, and ~~a decrease of $49 million due~~an increase in vendor and electric energy payments and increases in materials and supplies to ~~a change in regulatory deferrals, partially offset by higher earnings.~~

~~Power~~

~~Power’s operating cash flow~~ ~~decreased$11 million~~ ~~from~~ ~~$1,260 million~~ to ~~$1,249 million~~ ~~for the~~ ~~nine months~~ ~~ended~~ ~~September 30, 2017, as compared to the same period in 2016, due~~ primarily ~~to tax payments in 2017 as compared to tax refunds in 2016 and lower earnings,~~support our electric Advanced Metering Infrastructure program. This was partially offset by a ~~$68 million~~ decrease in ~~margin deposit requirements and a $30 million increase~~net accounts receivable due to improved collections following the delays from ~~net collection of counterparty receivables.~~COVID-19 moratoriums.

Short-Term Liquidity

~~We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements.~~ Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs.

During the second half of 2021 and continuing into 2023, forward energy prices have demonstrated considerable price volatility. This has led to significant variations in our collateral requirements. As of June 30, 2023, net cash collateral postings were approximately $426 million. While currently off their highs experienced during 2022, collateral postings could remain volatile in the future.

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Our total committed credit facilities and available liquidity as of ~~September~~June 30, ~~2017~~2023 were as follows:



Company/Facility	As of June 30, 2023
	Total Facility		Usage		Available Liquidity
	Millions
PSEG	$	1,500	$	152	$	1,348
PSE&G	1,000		318		682
PSEG Power	1,650		191		1,459
Total	$	4,150	$	661	$	3,489

Company/Facility As of September 30, 2017

Total
Facility
Usage
Available
Liquidity

Millions
PSEG $ 1,500
$ 215
$ 1,285

PSE&G 600
15
585

Power 2,100
182
1,918

Total $ 4,200
$ 412
$ 3,788

We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements, including to satisfy any additional collateral requirements. As of ~~September~~June 30, ~~2017,~~2023, our liquidity position, including our credit ~~facility capacity~~facilities and access to external financing, was ~~in excess of~~expected to be sufficient to meet our projected ~~maximum liquidity~~stressed requirements over our ~~12 month~~12-month planning horizon. ~~Our maximum~~PSEG analyzes its liquidity requirements ~~are based on~~using stress scenarios that ~~incorporate~~consider different events, including changes in commodity prices and thepotential impact of PSEG Power losing its investment grade credit rating from S&P or Moody’s, which would represent a ~~three~~two level downgrade from its current Moody’s and S&P ~~or Moody’s~~ ratings. In the event of a deterioration of PSEG Power’s

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credit rating, certain of PSEG Power’s agreements allow the counterparty to demand further performance assurance. The potential additional collateral that we would be required to post under these agreements if PSEG Power were to lose its investment grade credit rating was approximately ~~$899~~$709 million and ~~$783~~$878 million as of ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016,~~2022, respectively.

For additional information, see Item 1. Note ~~10.~~11. Debt and Credit Facilities.

Long-Term Debt Financing

During the next twelve months,,

•PSEG has ~~a floating rate $500~~$750 million ~~term loan~~of 0.84% Senior Notes maturing in November ~~2017. PSE&G~~2023,

•PSEG has ~~$400~~$750 million of ~~5.30% Medium-Term~~2.88% Senior Notes maturing in ~~May 2018 and $350~~June 2024,

•PSE&G has $325 million of ~~2.30%~~3.25% Medium-Term Notes, ~~maturing~~Series M, due September 2023, and

•PSE&G has $250 million of 3.75% Medium-Term Notes, Series I, due March 2024.

PSEG, PSEG Power, Energy Holdings, PSEG LI and Services participate in ~~September 2018.~~a corporate money pool, an aggregation of daily cash balances designed to efficiently manage their respective short-term liquidity needs, which are accounted for as intercompany loans. Long Island Electric Utility Servco, LLC (Servco) does not participate in the corporate money pool. Servco’s short-term liquidity needs are met through an account funded and owned by LIPA.

For ~~a discussion of our long-term debt issuances and maturities during 2017,~~additional information see Item 1. Note ~~10.~~11. Debt and Credit Facilities.

Common Stock Dividends

On July ~~18, 2017, our~~17, 2023, PSEG’s Board of Directors approved a ~~$0.43 dividend~~$0.57 per share of common stock dividend for the third quarter of ~~2017.~~2023. This reflects an indicative annual dividend rate of ~~$1.72~~$2.28 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant. For additional information related to cash dividends on our common stock, see Item 1. ~~Note16.~~Note 17. Earnings Per Share (EPS) and Dividends.

Credit Ratings

If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Credit Ratings shown are for securities that we typically issue. Outlooks are shown for ~~Corporate Credit Ratings (S&P) and Issuer Credit Ratings (Moody’s)~~the credit ratings at each entity and can be Stable, Negative, or Positive. There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if in

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their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security.

In April 2017, S&P published updated research and affirmed the ratings and outlooks of PSEG and PSE&G. In June 2017, S&P published updated research on Power and the rating and outlook remained unchanged. In July 2017, Moody’s upgraded PSEG’s senior unsecured rating to Baa1 from Baa2 and revised its outlook to Stable from Positive. Also in July, Moody’s affirmed the ratings at PSE&G and Power.

Moody’s (A)

S&P (B)

PSEG

~~Moody’s (A)~~

~~S&P (B)~~

~~PSEG~~

~~Outlook~~

~~Stable~~

~~Senior Notes~~

~~Baa1~~

~~BBB~~

~~Commercial Paper~~

~~PSE&G~~

~~Outlook~~

~~Stable~~

~~Mortgage Bonds~~

~~Aa3~~

~~Commercial Paper~~

~~Power~~

~~Outlook~~

~~Stable~~

~~Senior Notes~~

~~Baa1~~

~~BBB+~~

~~(A)~~

~~Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities.~~Outlook

Stable

Senior Notes

Baa2

BBB

Commercial Paper

PSE&G

~~(B)~~

~~S&P ratings range from AAA (highest) to D (lowest) for long-term securities and~~ Outlook

Stable

Mortgage Bonds

A1 ~~(highest) to D (lowest) for short-term securities.~~

Commercial Paper

PSEG Power

Outlook

Stable

Issuer Rating

Baa2

BBB

~~Table of Contents~~(A)Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities.

(B)S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities.

CAPITAL REQUIREMENTS

We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. There were no material changes to our projected capital expenditures as compared to amounts disclosed in our ~~2016~~2022 Form 10-K.

PSE&G

During the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2023, PSE&G made capital expenditures of ~~$2,118~~$1,336 million, primarily for T&D system ~~reliability.~~reliability and advanced electric metering. This ~~does not include expenditures for~~excludes cost of removal, net of salvage, of ~~$72~~$82 million associated with capital replacements, and expenditures for EE programs of approximately $203 million, which are included in operating cash flows.

In July 2017, PSE&G filed a petition with the BPU for a GSMP II program, requesting extension of our gas system modernization program through which PSE&G has proposed investing up to $540 million per year beginning in 2019 to continue to modernize our gas system. Under this proposed program, PSE&G plans to replace up to 1,250 miles of gas mains and associated service lines. This is not included in PSE&G’s projected capital expenditures.PSEG Power & Other

~~Power~~

During the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2023, PSEG Power & Other made capital expenditures of ~~$779~~$61 million, excluding ~~$124~~$47 million for nuclear fuel, primarily related to ~~our Keys, Sewaren 7, BH5~~various nuclear projects at PSEG Power and ~~other generation projects.~~various information technology projects at Services.

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~~ACCOUNTING MATTERS~~

~~For information related to recent accounting matters, see Item 1. Note 2. Recent Accounting Standards.~~


~~ITEM 3.~~	~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~

ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The risk inherent in our market-risk sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, equity security prices and interest rates as discussed in the Notes to the Condensed Consolidated Financial Statements. It is our policy to use derivatives to manage risk consistent with business plans and prudent practices. We have a Risk Management Committee comprised of executive officers who utilize a risk oversight function to ensure compliance with our corporate policies and risk management practices.

Additionally, we are exposed to counterparty credit losses in the event of non-performance or non-payment. We have a credit management process, which is used to assess, monitor and mitigate counterparty exposure. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on our financial condition, results of operations or net cash flows.

Commodity Contracts

The availability and price of energy-related commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market rules and other events. To reduce price risk caused by market fluctuations, we enter into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties. These contracts, in conjunction with physical sales and other services, help reduce risk and optimize the value of owned electric generation capacity.

Value-at-Risk (VaR) Models

VaR represents the potential losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. We estimate VaR across our commodity businesses.

MTM VaR consists of MTM derivatives that are economic hedges. The MTM VaR calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and some ~~load serving~~load-serving activities.

The VaR models used are variance/covariance models adjusted for the change of positions with 95% and 99.5% confidence levels and a one-day holding period for the MTM activities. The models assume no new positions throughout the holding periods; however, we actively manage our portfolio.

From ~~July~~April through ~~September 2017,~~June 2023, MTM VaR ~~remained relatively stable~~varied between a low of $5$54 million and a high of $9$86 million at the 95% confidence level. The range of VaR was narrower for the three months ended ~~September~~June 30, ~~2017~~2023 as compared with the year ended December 31, ~~2016.~~2022.

~~Table of Contents~~

MTM VaR
Three Months Ended September 30, 2017 Year Ended December 31, 2016
Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End $ 8
$ 26

Average for the Period $ 7
$ 16

High $ 9
$ 32

Low $ 5
$ 10

99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End $ 13
$ 40

Average for the Period $ 11
$ 25

High $ 15
$ 51

Low $ 8
$ 16



	MTM VaR
	Three Months Ended June 30, 2023		Year Ended December 31, 2022
	Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	56	$	122
Average for the Period	$	66	$	152
High	$	86	$	365
Low	$	54	$	70
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	87	$	191
Average for the Period	$	103	$	239
High	$	135	$	572
Low	$	85	$	110

See Item 1. Note ~~11.~~12. Financial Risk Management Activities for a discussion of credit risk.

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~~ITEM 4.~~	~~CONTROLS AND PROCEDURES~~

ITEM 4.CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

PSEG and PSE&G ~~and Power~~

We have established and maintain disclosure controls and procedures as defined under Rule 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) that are designed to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported and is accumulated and communicated to the Chief Executive Officer (CEO) and Chief Financial Officer (CFO) of each respective company, as appropriate, by others within the entities to allow timely decisions regarding required disclosure. We have established a disclosure committee which includes several key management employees and which reports directly to the CFO and CEO of each of PSEG ~~PSE&G~~ and ~~Power.~~PSE&G. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The CFO and CEO of each of PSEG and PSE&G ~~and Power~~ have evaluated the effectiveness of the disclosure controls and procedures and, based on this evaluation, have concluded that disclosure controls and procedures at each respective company were effective at a reasonable assurance level as of the end of the period covered by the report.

Internal Controls

PSEG and PSE&G ~~and Power~~

There have been no changes in internal control over financial reporting that occurred during the ~~third~~second quarter of ~~2017~~2023 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.

PART II. OTHER INFORMATION


~~ITEM 1.~~	~~LEGAL PROCEEDINGS~~

ITEM 1.LEGAL PROCEEDINGS

We are party to various lawsuits and environmental and regulatory matters, including in the ordinary course of business. For ~~additional~~ information regarding material legal proceedings, including updates to information reported in Item 3 of Part I of the ~~2016 Annual Report on~~ Form 10-K, see Part I, Item 1. Note 9.10. Commitments and Contingent Liabilities ~~and Item 5. Other Information.~~in this Quarterly Report on Form 10-Q.


~~ITEM 1A.~~	~~RISK FACTORS~~

ITEM 1A.RISK FACTORS

The discussion of our business and operations in this Quarterly Report on Form 10-Q should be read together with the risk factors contained in Part I, Item 1A of our ~~2016 Annual Report on~~ Form 10-K ~~and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017,~~ which ~~describe~~describes various risks and uncertainties that could have a material adverse impact on our business, prospects, financial position, results of operations or cash flows and could cause results to differ materially from those expressed elsewhere in this report. ~~Except as discussed below, there have been no material changes to the risk factors set forth in the above-referenced filings as of September 30, 2017.~~

~~Table of Contents~~

~~Cybersecurity attacks or intrusions could adversely impact our businesses.~~

Cybersecurity threats to the U.S. energy market infrastructure are increasing in sophistication, magnitude and frequency. We rely on information technology systems that utilize sophisticated digital systems and network infrastructure to operate our generation, transmission and distribution systems. We also store sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, employees, shareholders, customers and vendors on our systems and conduct power marketing and hedging activities. In addition, the operation of our business is dependent upon the information technology systems of third parties, including our vendors, regulators, RTOs and Independent System Operators (ISOs), among others. Our and third-party information technology systems may be vulnerable to cybersecurity attacks involving domestic or foreign sources. A cybersecurity attack may also leverage such information technology to cause disruptions at a third party. Cybersecurity impacts to our operations include:

~~disruption of the operation of our assets and the power grid,~~

~~theft of confidential company, employee, shareholder, vendor or customer information, which may cause us to be in breach of certain covenants and contractual obligations,~~

general business system and process interruption or compromise, including preventing us from servicing our customers, collecting revenues or the ability to record, process and/or report financial information correctly, and

~~breaches of vendors’ infrastructures where our confidential information is stored.~~

We have experienced and expect to continue to experience actual or attempted cyber-attacks on our information technology systems; however, none of these incidents has had a material impact on our operations or financial condition. If a significant cybersecurity event or breach should occur within our company or with one of our material vendors, we could be exposed to significant loss of revenue, material repair costs to intellectual and physical property, significant fines and penalties for non-compliance with existing laws and regulations, significant litigation costs, increased costs to finance our businesses, reputational damage and loss of confidence from our customers, regulators, investors, vendors and employees. Similarly, a significant cybersecurity event or breach experienced by a competitor, regulatory authority, RTO, ISO, or vendor could also materially impact our business and results of operations via enhanced legal and regulatory requirements. For a discussion of state and federal cybersecurity regulatory requirements and information regarding our cybersecurity program, see Part 1, Item 1. Regulatory Issues in our Annual Report on Form 10-K for the year ended December 31, 2016 and Item 5. Other Information in this Quarterly Report on Form 10-Q.

The market for cybersecurity insurance is relatively new and coverage available for cybersecurity events may evolve as the industry matures. While we maintain insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damage we experience.


~~ITEM 2.~~	~~UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS~~

~~The following table indicates our common share repurchases in the open market to satisfy obligations under various equity compensation awards during the~~ ~~third~~ ~~quarter of~~ ~~2017~~.

Three Months Ended September 30, 2017
Total Number
of Shares
Purchased

Average
Price Paid
per Share

July 1 - July 31 —
$ —

August 1 - August 31 135,277
$ 45.25

September 1- September 30 —
$ —

~~Table of Contents~~

ITEM 5. OTHER INFORMATION

Certain information ~~reported in the 2016 Annual Report on Form 10-K is updated below. Additionally, certain information~~ is provided below for new matters that have arisen subsequent to the filing of the ~~2016 Annual Report on~~ Form 10-K and the ~~Quarterly Report on Form 10-Q~~first quarter 2023 10-Q.

Director and Officer Rule 10b5-1 and non-Rule 10b5-1 Trading Plans

During the three months ended June 30, 2023, certain of our officers and directors adopted or terminated trading plans for the ~~quarters ended March 31, 2017 and June 30, 2017. References~~sale of PSEG common stock which are intended to satisfy the ~~related pages~~affirmative defense of Rule 10b5-1(c) of the Exchange Act, as amended, as shown in the following table:

Name and Title

Action

Date

Aggregate Number of Shares to be Sold or Purchased

Expiration (A)

Rose M. Chernick

Adoption

May 22, 2023

Sell 1,800 shares

May 3, 2024

Vice President and Controller

(A) Expires on the ~~Forms 10-K and 10-Q~~date shown or such earlier date upon the completion of all trades under the plan or the occurrence of such other termination events as ~~printed and distributed.~~specified in the plan, including but not limited to termination of the plan by Ms. Chernick.

~~Employee Relations~~

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Federal Regulation

Transmission Planning Proceedings

December 31, ~~2016~~2022 Form 10-K page ~~15.~~ 10. In ~~2016, six~~June 2023, FERC issued a rule directing the North American Electric Reliability Corporation (NERC) to either change existing reliability standards or create a new standard that will require regional transmission organizations (RTOs) like PJM to plan for extreme weather events. FERC also issued a rule directing RTOs to file one-time informational reports describing their current and future processes for conducting extreme weather assessments.

Capacity Market Issues

December 31, 2022 Form 10-K page 11 and March 31, 2023 Form 10-Q page 66. In June 2023, FERC approved PJM’s request to delay the base residual auctions for 2025-2029, starting with postponing the June 2023 base residual auction for delivery year 2025/2026 until June 2024 while PJM considers changes to its capacity markets. The following three base residual auctions would occur at six-month intervals. PJM is currently examining various capacity market reforms, including changes to how capacity resources are compensated for their availability and the imposition of more stringent winterization requirements.

Compliance—Reliability Standards

December 31, 2022 Form 10-K page 11 and March 31, 2023 Form 10-Q page 66. FERCandthe NERC are conducting a joint inquiry into the operation of the Bulk Power System (BPS) during Winter Storm Elliott that struck in late 2022. We received and responded to information requests from FERC and NERC regarding the performance of our ~~eight labor unions ratified extensions~~generators during the storm. Relatedly, in February 2023, FERC approved additional reliability standards governing extreme cold weather preparedness and operations, which will begin going into effect in 2024. In addition, FERC recently directed NERC to revise existing or develop new transmission planning standards that will require enhanced planning for extreme weather events.

State Regulation

New Jersey EMP and Future of Gas Stakeholder Proceeding

March 31, 2023 Form 10-Q page 66. In February 2023, Governor Murphy issued three EOs, one of which directs the BPU to immediately convene a stakeholder process on the future of gas to develop a plan to meet the State’s current EMP goal to reduce emissions by 50% versus 2006 levels by 2030. In March 2023, the BPU opened a stakeholder proceeding to implement such EO that will commence in August 2023 with a two-day technical conference. This proceeding will consider the possible development of a “clean heat standard” or other market mechanisms to support the State’s goals, among other things. Additionally, in April of 2023 the governor’s office Council on the Green Economy initiated a “Clean Buildings Working Group” that is considering pathways for building electrification and meeting gas utility emissions reduction goals, including development of a clean heat standard.PSE&G was invited to participate in this working group focused on strategic planning. We cannot predict the impact on our business or results of operations from these stakeholder proceedings, or any laws, rules, or regulations promulgated as a result thereof, particularly as they may relate to PSEG Power’s nuclear energy generating stations and PSE&G’s electric transmission and gas distribution assets.

Energy Efficiency, Triennial Review

March 31, 2023 Form 10-Q page 66. In May 2023, rather than issue a single Order as originally contemplated, the BPU issued its first Energy Efficiency Framework Order, which addresses program administration and design, cost recovery and filing requirements, among other things. In July 2023, the BPU issued a second Order related to the Energy Efficiency Framework. This Order addresses goals, a performance incentive mechanism, building decarbonization and demand response.

BGS Process

December 31, 2022 Form 10-K page 13 and March 31, 2023 Form 10-Q page 67. In June 2023, the State’s electric distribution companies (EDCs), including PSE&G, filed their ~~collective bargaining agreements with us, with expiration dates from 2019 to 2021. In 2017, each~~annual joint proposal for the conduct of the ~~remaining two unions ratified extensions of their collective bargaining agreements~~February 2024 BGS auction covering energy years 2025 through 2027. As was directed by a November 2022 BPU order, PSE&G participated in a working group led by BPU Staff to consider proposals for a commercial direct current, fast-charging (DCFC) rate solution. PSE&G’s proposal included in the June 2023 joint EDC BGS filing is for a two-year DCFC BGS rate pilot program to begin June 1, 2024.Also in accordance with usthe November 2022 order’s directive that the EDCs implement a rate solution for residential EV charging customers, in May 2023, the BPU approved PSE&G’s proposal for a BGS time-of-use rate solution for residential EV charging, with ~~expiration dates in 2021 and 2022.~~rates effective June 1, 2023.

~~Federal Regulation~~Environmental Matters

~~FERC~~Environmental Justice (EJ)

~~Energy Clearing Prices/Price Formation Initiatives~~

December 31, ~~2016~~2022 Form 10-K page 16 and March 31, ~~2017 Form 10-Q on page 76.~~ Energy clearing prices in the markets in which we operate are generally based on bids submitted by generating units. Under FERC-approved market rules, bids are subject to price caps and mitigation rules applicable to certain generation units. FERC rules also govern the overall design of these markets. At present, all units within a delivery zone receive a clearing price based on the bid of the marginal unit (i.e. the last unit that must be dispatched to serve the needs of load) which can vary by location. In addition, recent rule changes in the energy markets administered by PJM and ISO-NE (see Capacity Market Issues below) impose rigorous performance obligations and nonperformance penalties on resources during times of system stress. These FERC rules provide an opportunity for bonus payments or require the payment of penalties depending on whether a unit is available during a performance hour.

FERC has also recently ordered certain favorable changes to energy market price formation rules improving shortage pricing and enhancing bidding flexibility for units. We continue to advocate in this context for additional changes in market rules that would provide more transparency about energy market prices. We cannot predict what action FERC might ultimately take, but such an examination could lead to future rule changes.

In June 2017, PJM issued an energy price formation proposal to address a flaw in the energy market in which energy prices during off-peak periods often do not reflect the production costs of generators during these periods even though they are serving load. PJM’s proposal would allow large, inflexible units to set price. If placed into effect, this proposal will improve price formation by ensuring that the marginal costs of units serving load will be better reflected in clearing prices. We cannot predict the outcome of this matter.

~~Notice of Proposed Rulemaking on Baseload Generation~~

In September 2017, the Secretary of the U.S. Department of Energy issued a Notice of Proposed Rulemaking (NOPR) to allow a full recovery of costs for certain eligible units physically located within the FERC-approved organized markets. The NOPR directs FERC to take final action within 60 days. The NOPR contemplates a cost-of-service payment and a fair rate of return for units that are able to provide certain essential energy and ancillary reliability services, have a 90-day fuel supply on site and are not subject to cost-of-service rate regulation by any State or local authority. We are participating in this proceeding, but we are unable to predict the outcome.

~~Capacity Market Issues~~

~~December 31, 2016 Form 10-K page 16, March 31, 2017 Form 10-Q on page 76 and June 30, 2017 Form 10-Q on page 83.~~ PJM, the New York Independent System Operator (NYISO) and the Independent System Operator New England, Inc. each have capacity markets that have been approved by FERC. FERC regulates these markets and continues to examine whether the market design for each of these three capacity markets is working optimally. Various forums are considering how the competitive market framework can incorporate or be reconciled with state public policies that support particular resources or resource attributes, whether generators are being sufficiently compensated in the capacity market and whether subsidized resources may be adversely affecting capacity market prices. FERC held a technical conference to seek input from the industry on potential options to integrate public policy goals in wholesale markets. We cannot predict what action, if any, FERC might take with regard to capacity market designs.

~~Capacity Market Issues—PJM~~

~~December 31, 2016 Form 10-K page 16, March 31, 2017 Form 10-Q on page 76 and June 30, 2017~~2023 Form 10-Q page ~~83.~~ ~~PJM~~67. In April 2023, the New Jersey Department of Environmental Protection (NJDEP) finalized its EJ regulations. The regulations supersede a previously issued a series of white papers in response to public policies that seek to recognize value associated with generation plants beyond their cost effectiveness and reliability attributes. The three proposals are intended to spur stakeholder discussion and include both potential capacity and energy market reforms. The first energy market reform (see Energy Clearing Prices/Price Formation Initiatives) would allow inflexible generating units to set prices resulting in reduced uplift payments and improvedEJ

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price signals while the second energy market reform contemplates a voluntary carbon pricing program where states that elect to participate in the program would agree to put a price on carbon emissions. The capacity market proposal contemplates a two-stage capacity auction which, in its current form, would improve prices for unsubsidized resources, but would still continue to provide capacity payments for subsidized resources.

~~Transmission Regulation~~

~~December 31, 2016 Form 10-K page 18.~~ In October 2017, PSE&G filed its 2018 Annual Formula Rate Update with FERC which requests approximately $212 million in increased annual transmission revenues effective January 1, 2018, subject to true-up. Each year, transmission revenues are adjusted to reflect items such as updating estimates used in the filing with actual data. For additional information about our transmission formula rate, see Part I Item 1. Note 5. Rate Filings.

~~Transmission Regulation~~—~~Transmission Policy Developments~~

~~December 31, 2016 Form 10-K page 18, March 31, 2017 Form 10-Q on page 77 and June 30, 2017 Form 10-Q on page 83.~~

~~In a February 2016 order, FERC reversed a previous~~administrative order and ~~accepted~~require review of potential EJ impacts from a ~~filing by~~wide variety of environmental permit applications at certain designated facilities. The NJDEP may impose permit conditions or deny permits if the PJM transmission owners seeking authority to assign costs for Regional Transmission Expansion Plan projects (subject to PJM Board approval requirements) solely addressing localized needs to customers within the local transmission owner’s zone. FERC’s action in this order provides an exemption from the Order 1000 open window procedures for projects constructed by transmission owners to meet local transmission planning criteria. FERC’s orders have been challenged at the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit) and PSE&G has intervened in support of FERC.

~~In April 2017, the PJM Board announced~~impacts cannot be satisfactorily mitigated. We do not currently anticipate that it would be lifting the previously disclosed suspension of the Artificial Island transmission project and approved the award to PSE&G of the construction of necessary upgrade work at a cost of approximately $130 million. In October 2017, FERC accepted PJM’s filing on the grounds that PJM correctly applied its Tariff. However, FERC deferred a ruling on whether the cost allocation methodology applied to the Artificial Island project is appropriate. FERC will decide this issue in a separate proceeding that is currently pending. We are unable to predict the outcome.

~~Nuclear Regulatory Commission (NRC)~~

~~December 31, 2016 Form 10-K page 20.~~ The NRC continues to evaluate potential revisions to its requirements in connection with its operational and safety reviews of nuclear facilities in the United States as a result of the Fukushima Daiichi incident. We are also subject to cybersecuritythese regulations ~~promulgated by the NRC.~~

We are unable to predict the final outcome of these reviews or the cost of any actions we would need to take to comply with any new regulations, including possible modifications to our Salem, Hope Creek and Peach Bottom facilities, but such cost could be material.

~~State Regulation~~

~~Cybersecurity Requirements for Regulated Entities~~

~~December 31, 2016 Form 10-K page 21.~~ In March 2016, the BPU issued an order for the regulated electric, natural gas and water/wastewater utilities to further reduce the potential for cyber threats to the reliability and resiliency of utility service and to protect customers’ information. The order requires these regulated utilities, including PSE&G, to, among other conditions, implement a cybersecurity program that defines and implements organization accountabilities and responsibilities for cyber risk management activities, and establishes policies, plans, processes and procedures for identifying and mitigating cyber risk to critical systems. New Jersey utilities, including PSE&G, were required to be compliant with these requirements by October 1, 2017. We have submitted the required certification of compliance to the BPU.

In an effort to reduce the likelihood and severity of cyber incidents, we have a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of our company and our customers’ information and our systems. In addition, we are subject to maintaining key cybersecurity controls to meet mandatory cybersecurity regulatory requirements. Our cybersecurity program is built on technical, procedural, and people-focused measures to detect, protect against, respond to, and recover from cyber threats to our systems and information including company, employee and customer data. Features of our program include: identifying critical information and systems; conducting cyber risk assessments of our and third party systems; maintaining awareness of cyber threats and vulnerabilities through partnerships with public and private entities, as well as industry groups; maintaining and testing our cybersecurity incident response plans and systems; training personnel on cybersecurity issues; and raising cybersecurity awareness throughout our company with electronic notices and seminars. We cannot assure that our cybersecurity program will be effective in preventing or mitigating cybersecurity incidents. For a discussion of the risks associated with cybersecurity threats, see Item 1A. Risk Factors.

~~Table of Contents~~

~~Energy Efficiency 2017 Program (EE 2017)~~

In August 2017, the BPU approved PSE&G’s petition for an Energy Efficiency 2017 Program (EE 2017) to extend three existing energy efficiency subprograms (multi-family, direct install and hospital efficiency) and establish two new residential energy efficiency offerings. The two new offerings include deployment of smart thermostats and a pilot program to provide residential customers with energy usage information enabling them to reduce consumption. The Order allows PSE&G to extend the subprogram offerings and establish the residential energy efficiency sub-programs under its existing energy efficiency clause recovery process. The EE 2017 allows for $69 million of additional investment and $16 million of additional administrative and information technology costs. The EE 2017 was added as the 11th component of the GPRC rate effective September 1, 2017.

~~Consolidated Tax Adjustments (CTA)~~

~~December 31, 2016 Form 10-K page 21.~~ ~~New Jersey is one of only a few states that make CTA in setting rates for regulated utilities. These adjustments to rate base are madeduring the rate setting process and~~are intended to allocate to utility customers a portion of the tax benefits realized from the filing of a consolidated federal tax return by the utility’s parent corporation. The BPU has been considering the appropriateness of the adjustment and the methodology and mechanics of the calculation for some time. In October 2014, the BPU approved a proposal by its Staff that limits the tax benefit period to be considered in the calculation to five years, sets the distribution rate base adjustment at 25% of any such tax benefit and eliminates from the process any tax benefits tied to transmission earnings. In accordance with this October action, this CTA policy will be applied only with respect to future distribution rate base cases. In November 2014, the New Jersey Division of Rate Counsel appealed the BPU’s decision and in September 2017, the New Jersey Superior Court, Appellate Division granted that appeal on procedural grounds. While the issue has now been remanded to the BPU, it is not expected that application of a CTA will have a material impact on ~~PSE&G’s current earnings~~the business, operations, financial position or ~~in its upcoming rate case filing.~~cash flows of PSEG and PSE&G.

~~Environmental Matters~~New Jersey Protecting Against Climate Threats (NJ PACT)

~~Air Pollution Control~~

~~Hazardous Air Pollutants Regulation~~

December 31, ~~2016~~2022 Form 10-K page ~~22.~~ ~~In June 2015, the U.S. Supreme Court held that it was unreasonable for the EPA~~16. This NJDEP regulatory reform is expected to ~~refuse~~result in changes to ~~consider the materiality of costs in determining whether to regulate hazardous~~existing air pollutants from power plants. In April 2016, the EPA released the final Supplemental Finding that considers the materiality of costs in determining whether to regulate hazardous air pollutants from power plantsand land use regulations in response to ~~the U.S. Supreme Court’s ruling. Industry participants and various state authorities have filed petitions with the D.C. Circuit challenging the EPA’s Supplemental Finding. The D.C. Circuit~~anticipated impacts of climate change. It has already published a final, updated regulation pertaining to inland flood protection which is ~~holding the case~~intended to protect new development from river or stream flooding, which went into effect in ~~abeyance pending further directions from the EPA.~~July 2023. We do not ~~expect~~currently anticipate any specific material impacts from this ~~Supplemental Finding~~regulation.

We continue to ~~impact operation of our facilities.~~

~~Climate Change~~

CO₂~~Regulation under~~assess the ~~Clean Air Act (CAA)~~

~~December 31, 2016 Form 10-K page 23.In March 2017, the President of the United States issued an Executive Order that instructed the EPA to review the New Source Performance Standards that establish emissions standards for CO~~₂ for certain new fossil power plants and the Clean Power Plan (CPP), a greenhouse gas emissions regulation under the CAA for existing power plants that establishes state-specific emission rate targets based on implementation of the best system of emission reduction. In April 2017, the D.C. Circuit granted the EPA’s motion to hold the case in abeyance for at least 60 days while the agency reviews the rule, which was subsequently extended by the D.C. Circuit in August 2017. In October 2017, upon completion of the review, the EPA Administrator signed a proposed repeal of the CPP. The EPA Administrator concluded that the CPP exceeds the EPA’s statutory authority by considering measures that are beyond the control of the owners of the affected sources (fossil fuel-fired electric generating units). Whether the EPA chooses to propose a replacement rule has not been decided. PSEG cannot estimate thepotential impact of other proposed NJ PACT regulations, which include proposed real estate and land use regulations that could have cost implications for business operations, including the construction of new facilities or upgrades to existing utility infrastructure. Such expenditures could materially affect the continued economic viability and/or cost to construct one or more such facilities. However, the impacts of these ~~actions on our business~~new rules are both site and ~~future results~~activity specific to the proposed development and therefore can only be determined during the project phases of ~~operations at this time.~~specific projects.

~~Regional Greenhouse Gas Initiative (RGGI)~~

~~December 31, 2016 Form 10-K page 23.~~ ~~In response to concerns over global climate change, some states have developed initiatives to stimulate national climate legislation through CO~~₂emission reductions in the electric power industry. New Jersey withdrew from RGGI in 2012. However, certain northeastern states (RGGI States), including New York and Connecticut where we have generation facilities, have~~state-specific rules in place to enable the RGGI regulatory mandate in each state to cap and reduce CO~~₂ ~~emissions. These rules make allowances available through a regional auction whereby generators may acquire allowances that are each equal to one ton of CO~~₂ ~~emissions. Generators are required to submit an allowance for each ton emitted over a three-year period. Allowances are available through the auction or through secondary markets.~~

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~~In September 2017, the RGGI States announced their new post-2020 program for a cap on regional CO~~₂ ~~emissions, which would require a decline in CO~~₂ ~~emissions in 2021 and each year thereafter, resulting in a 30% reduction in the CO~~₂ ~~emissions cap by 2030.~~

~~Water Pollution Control~~

~~Steam Electric Effluent Guidelines~~

~~December 31, 2016 Form 10-K page 23, March 31, 2017 Form 10-Q on page 77 and June 30, 2017 Form 10-Q on page 85.~~ In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater, and gasification wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power’s Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges and that are regulated under this rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the rule.

In April 2017, the EPA announced that it had granted a petition for reconsideration of the ELG Rule and issued an administrative stay of the compliance dates in the rule that were the subject of pending litigation. In June 2017, the EPA proposed a rule to postpone the compliance deadlines for the BAT limitations for the aforementioned waste streams. In September 2017, the EPA issued a rule postponing for two years compliance dates related solely to bottom ash transport water and flue gas desulfurization wastewater. The EPA has announced plans to issue a new rule by November 2020 addressing revised requirements and compliance dates for these two waste streams. Power is unable to determine how this will ultimately impact its compliance requirements or its financial condition and results of operations.

~~Cooling Water Intake Structure~~

~~December 31, 2016 Form 10-K page 24.~~ In May 2014, the EPA issued a final cooling water intake rule under Section 316(b) of the Clean Water Act (CWA) that establishes new requirements for the regulation of cooling water intakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. In September 2014, several environmental non-governmental groups and certain energy industry groups filed petitions for review of the rule and the case has been assigned to the U.S. Second Circuit Court of Appeals (Second Circuit). Environmental organizations, including but not limited to the environmental petitioners in the Second Circuit, have also filed suit under the Endangered Species Act. The cases were subsequently consolidated at the Second Circuit and a decision remains pending.

~~Table of Contents~~


~~ITEM 6.~~	~~EXHIBITS~~

ITEM 6.EXHIBITS

A listing of exhibits being filed with this document is as follows:



a. PSEG:
Exhibit 1010.1:		~~Key Executive Severance~~2021 Long-Term Incentive Plan ~~of Public Service Enterprise Group Incorporated, Amended effective July 18, 2017~~- Performance Share Units Award Agreement
Exhibit ~~12:~~10.2:		~~Computation of Ratios of Earnings to Fixed Charges~~2021 Long-Term Incentive Plan - Restricted Stock Unit Award Agreement
Exhibit 10.3:		2021 Equity Compensation Plan for Outside Directors - Restricted Stock Unit Award Agreement
Exhibit 31:		Certification by Ralph ~~Izzo~~LaRossa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.1:		Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32:		Certification by Ralph ~~Izzo~~LaRossa Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.1:		Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:		Inline XBRL Instance Document - The Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
Exhibit 101.SCH:		Inline XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		Inline XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		Inline XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		Inline XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		Inline XBRL Taxonomy Extension Definition Document
Exhibit 104:		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

b. PSE&G:
Exhibit 1010.1:		~~Key Executive Severance~~2021 Long-Term Incentive Plan ~~of Public Service Enterprise Group Incorporated, Amended effective July 18, 2017~~- Performance Share Units Award Agreement
Exhibit ~~12.1:~~10.2:		~~Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements~~2021 Long-Term Incentive Plan - Restricted Stock Unit Award Agreement
Exhibit 10.3:		2021 Equity Compensation Plan for Outside Directors - Restricted Stock Unit Award Agreement
Exhibit 31.2:		Certification by Ralph ~~Izzo~~LaRossa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.3:		Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32.2:		Certification by Ralph ~~Izzo~~LaRossa Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.3:		Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:		Inline XBRL Instance Document - The Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
Exhibit 101.SCH:		Inline XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		Inline XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		Inline XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		Inline XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		Inline XBRL Taxonomy Extension Definition Document
Exhibit 104:		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
~~c. Power:~~
~~Exhibit 10~~	~~Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 18, 2017~~
~~Exhibit 12.2:~~	~~Computation of Ratios of Earnings to Fixed Charges~~
~~Exhibit 31.4:~~	~~Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act~~
~~Exhibit 31.5:~~	~~Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act~~
~~Exhibit 32.4:~~	~~Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code~~
~~Exhibit 32.5:~~	~~Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code~~
~~Exhibit 101.INS:~~	~~XBRL Instance Document~~
~~Exhibit 101.SCH:~~	~~XBRL Taxonomy Extension Schema~~
~~Exhibit 101.CAL:~~	~~XBRL Taxonomy Extension Calculation Linkbase~~
~~Exhibit 101.LAB:~~	~~XBRL Taxonomy Extension Labels Linkbase~~
~~Exhibit 101.PRE:~~	~~XBRL Taxonomy Extension Presentation Linkbase~~
~~Exhibit 101.DEF:~~	~~XBRL Taxonomy Extension Definition Document~~

Table of Contents

SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.


PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)

By:		P~~UBLIC~~/S~~ERVICE~~ E~~NTERPRISE~~ G~~ROUP~~ I~~NCORPORATED~~/ ROSE M. CHERNICK
~~(Registrant)~~

~~By:~~	/S~~/ STUART~~ ~~J. BLACK~~
	~~Stuart J. Black~~ Rose M. Chernick Vice President and Controller (Principal Accounting Officer)

Date: ~~October 31, 2017~~

August 1, 2023

~~Table of Contents~~

SIGNATURE


PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant)

By:		P~~UBLIC~~/S~~ERVICE~~ E~~LECTRIC~~ AND GAS/ ROSE M. C~~OMPANY~~HERNICK
~~(Registrant)~~

~~By:~~	/S~~/ STUART~~ ~~J. BLACK~~
	~~Stuart J. Black~~ Rose M. Chernick Vice President and Controller (Principal Accounting Officer)

Date: ~~October 31, 2017~~August 1, 2023

~~Table of Contents~~

~~SIGNATURE~~



~~PSEG POWER~~ ~~LLC~~
~~(Registrant)~~

~~By:~~	/S~~/ STUART~~ ~~J. BLACK~~
	~~Stuart J. Black~~ ~~Vice President and Controller~~ ~~(Principal Accounting Officer)~~

~~Date: October 31, 2017~~


					Page
FORWARD-LOOKING STATEMENTS					ii
FILING FORMAT					iii
PART I. FINANCIAL INFORMATION

Item 1.			Financial Statements		~~Page~~
~~FORWARD-LOOKING STATEMENTS~~			ii
~~FILING FORMAT~~		~~iii~~
~~PART I. FINANCIAL INFORMATION~~
~~Item 1.~~	~~Financial Statements~~
	Public Service Enterprise Group Incorporated	1
			Public Service Electric and Gas Company		67
			~~PSEG Power LLC~~		11
	Notes to Condensed Consolidated Financial Statements
			Note 1. Organization ~~and~~, Basis of Presentation and Significant Accounting Policies		1613
			Note 2. ~~Recent Accounting Standards~~ Revenues		1614
			Note 3. Early Plant ~~Retirements~~Retirements/Asset Dispositions and Impairments		1920
			Note 4. Variable Interest Entity (VIE)		21

			Note 5. Rate Filings		21
			Note 6. ~~Financing Receivables~~Leases		2223
			Note 7. ~~Available-for-Sale Securities~~Financing Receivables		2523
			Note 8. Trust Investments		25
			Note 9. Pension and Other Postretirement Benefits (OPEB)		3031
			Note 9.10. Commitments and Contingent Liabilities		3233
			Note ~~10.~~11. Debt and Credit Facilities		4038
			Note ~~11.~~12. Financial Risk Management Activities		4140
			Note ~~12.~~13. Fair Value Measurements		4644
			Note ~~13.~~14. Other Income ~~and Deductions~~(Deductions)		5449
			Note ~~14.~~15. Income Taxes		5550
			Note ~~15.~~16. Accumulated Other Comprehensive Income (Loss), Net of Tax		5652
			Note ~~16.~~17. Earnings Per Share (EPS) and Dividends		6054
			Note ~~17.~~18. Financial Information by Business ~~Segments~~Segment		6155
			Note ~~18.~~19. Related-Party Transactions		6257
			~~Note 19. Guarantees of Debt~~Item 2.	64
~~Item 2.~~	Management’s Discussion and Analysis of Financial Condition and Results of Operations	6758
			Executive Overview of ~~2017~~2023 and Future Outlook		6758
			Results of Operations		7564
			Liquidity and Capital Resources		8069
			Capital Requirements		8271
Item 3.			~~Accounting Matters~~		82
~~Item 3.~~	Quantitative and Qualitative Disclosures About Market Risk	8272
Item 4.			Controls and Procedures		8373

PART II. OTHER INFORMATION
Item 1.			Legal Proceedings		8373
Item 1A.			Risk Factors		8373
Item 2.5.			~~Unregistered Sales of Equity Securities and Use of Proceeds~~Other Information		8473
Item 5.6.			~~Other Information~~Exhibits		8576
~~Item 6.~~			~~Exhibits~~Signatures		8977
	~~Signatures~~	90



	June 30, 2023		December 31, 2022
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	547	$	465
Accounts Receivable, net of allowance of $290 in 2023 and $323 in 2022	1,422		1,944
Tax Receivable	8		79
Unbilled Revenues, net of allowance of $4 in 2023 and $16 in 2022	190		322
Fuel	200		420
Materials and Supplies, net	645		540
Prepayments	365		93
Derivative Contracts	91		18
Regulatory Assets	358		369
Assets Held for Sale	—		20
Other	37		33
Total Current Assets	3,863		4,303
PROPERTY, PLANT AND EQUIPMENT	47,193		45,924
Less: Accumulated Depreciation and Amortization	(10,333)		(9,982)
Net Property, Plant and Equipment	36,860		35,942
NONCURRENT ASSETS
Regulatory Assets	4,813		4,404
Operating Lease Right-of-Use Assets	170		176
Long-Term Investments	302		624
Nuclear Decommissioning Trust (NDT) Fund	2,383		2,230
Long-Term Tax Receivable	—		5
Long-Term Receivable of Variable Interest Entity (VIE)	562		551
Rabbi Trust Fund	185		183
Intangibles	14		14
Derivative Contracts	62		15
Other	291		271
Total Noncurrent Assets	8,782		8,473
TOTAL ASSETS	$	49,505	$	48,718




	September 30, 2017			December 31, 2016
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	1,250		$	500
Commercial Paper and Loans	202			388
Accounts Payable	1,305			1,459
Derivative Contracts	7			13
Accrued Interest	136			97
Accrued Taxes	146			31
Clean Energy Program	184			142
Obligation to Return Cash Collateral	132			132
Regulatory Liabilities	44			88
Other	425			426
Total Current Liabilities	3,831			3,276
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	8,931			8,658
Regulatory Liabilities	89			118
Asset Retirement Obligations	748			726
OPEB Costs	1,301			1,324
OPEB Costs of Servco	474			452
Accrued Pension Costs	504			568
Accrued Pension Costs of Servco	113			128
Environmental Costs	399			401
Derivative Contracts	1			3
Long-Term Accrued Taxes	173			180
Other	195			211
Total Noncurrent Liabilities	12,928			12,769
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)
CAPITALIZATION
LONG-TERM DEBT	11,274			10,895
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000 shares; issued, 2017 and 2016—534 shares	4,938			4,936
Treasury Stock, at cost, 2017 and 2016—29 shares	(750		)	(717		)
Retained Earnings	9,140			9,174
Accumulated Other Comprehensive Loss	(204		)	(263		)
Total Stockholders’ Equity	13,124			13,130
Total Capitalization	24,398			24,025
TOTAL LIABILITIES AND CAPITALIZATION	$	41,157		$	40,070



	June 30, 2023		December 31, 2022
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	2,075	$	1,575
Commercial Paper and Loans	1,197		2,200
Accounts Payable	1,050		1,271
Derivative Contracts	66		124
Accrued Interest	141		134
Accrued Taxes	11		12
Clean Energy Program	229		145
Obligation to Return Cash Collateral	92		290
Regulatory Liabilities	339		384
Other	550		545
Total Current Liabilities	5,750		6,680
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	6,345		5,725
Regulatory Liabilities	2,157		2,240
Operating Leases	166		169
Asset Retirement Obligations	1,525		1,499
OPEB Costs	400		410
OPEB Costs of Servco	466		455
Accrued Pension Costs	691		705
Accrued Pension Costs of Servco	81		82
Environmental Costs	219		231
Derivative Contracts	8		33
Long-Term Accrued Taxes	57		66
Other	193		199
Total Noncurrent Liabilities	12,308		11,814
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 10)
CAPITALIZATION
LONG-TERM DEBT	16,394		16,495
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000 shares; issued, 2023 and 2022—534 shares	5,054		5,065
Treasury Stock, at cost, 2023 and 2022—37 shares	(1,386)		(1,377)
Retained Earnings	11,900		10,591
Accumulated Other Comprehensive Loss	(515)		(550)
Total Stockholders’ Equity	15,053		13,729
Total Capitalization	31,447		30,224
TOTAL LIABILITIES AND CAPITALIZATION	$	49,505	$	48,718



	Six Months Ended
	June 30,
	2023		2022
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	1,878	$	129
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	561		552
Amortization of Nuclear Fuel	94		93
Losses on Asset Dispositions and Impairments	—		38
Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual	5		40
Provision for Deferred Income Taxes and ITC	377		(379)
Non-Cash Employee Benefit Plan (Credits) Costs	19		(120)
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	(1,066)		951
Cost of Removal	(82)		(63)
Net Change in Regulatory Assets and Liabilities	(189)		(188)
Net (Gains) Losses and (Income) Expense from NDT Fund	(132)		222
Net Change in Certain Current Assets and Liabilities:
Tax Receivable	71		1
Accrued Taxes	(3)		(98)
Prepayments	(270)		(199)
Cash Collateral	1,095		(1,244)
Obligation to Return Cash Collateral	(198)		552
Other Current Assets and Liabilities	283		130
Employee Benefit Plan Funding and Related Payments	(21)		(16)
Other	(13)		(45)
Net Cash Provided By (Used In) Operating Activities	2,409		356
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(1,444)		(1,291)
Proceeds from Sales of Trust Investments	721		862
Purchases of Trust Investments	(742)		(876)
Proceeds from Sales of Equity Method Investments	290		—
Proceeds from Sales of Long-Lived Assets	20		1,890
Other	36		(54)
Net Cash Provided By (Used In) Investing Activities	(1,119)		531
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	247		(956)
Proceeds from Short-Term Loans	750		2,000
Payment of Short-Term Loans	(2,000)		(1,250)
Issuance of Long-Term Debt	900		1,750
Payment of Long-Term Debt	(500)		—
Payments for Share Repurchase Program	—		(500)
Cash Dividends Paid on Common Stock	(569)		(541)
Other	(32)		(7)
Net Cash Provided By (Used In) Financing Activities	(1,204)		496
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	86		1,383
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	511		863
Cash, Cash Equivalents and Restricted Cash at End of Period	$	597	$	2,246
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	63	$	325
Interest Paid, Net of Amounts Capitalized	$	347	$	276
Accrued Property, Plant and Equipment Expenditures	$	413	$	381




	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
OPERATING REVENUES	$	2,263		$	2,450		$	6,988		$	6,971
OPERATING EXPENSES
Energy Costs	638			866			2,100			2,326
Operation and Maintenance	680			776			2,100			2,215
Depreciation and Amortization	252			231			1,721			679
Total Operating Expenses	1,570			1,873			5,921			5,220
OPERATING INCOME	693			577			1,067			1,751
Income from Equity Method Investments	3			3			11			9
Other Income	66			47			208			139
Other Deductions	(10		)	(8		)	(30		)	(39		)
Other-Than-Temporary Impairments	(5		)	(5		)	(9		)	(25		)
Interest Expense	(100		)	(99		)	(289		)	(288		)
INCOME BEFORE INCOME TAXES	647			515			958			1,547
Income Tax Expense	(252		)	(188		)	(340		)	(562		)
NET INCOME	$	395		$	327		$	618		$	985
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC	505			505			505			505
DILUTED	507			508			507			508
NET INCOME PER SHARE:
BASIC	$	0.78		$	0.65		$	1.22		$	1.95
DILUTED	$	0.78		$	0.64		$	1.22		$	1.94
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.43		$	0.41		$	1.29		$	1.23



	Common Stock			Treasury Stock			Retained Earnings		Accumulated Other Comprehensive Income (Loss)
	Shs.	Amount		Shs.	Amount						Total
Balance as of March 31, 2023	534	$	5,045	(37)	$	(1,391)	$	11,594	$	(522)	$	14,726
Net Income	—	—		—	—		591		—		591
Other Comprehensive Income (Loss), net of tax (expense) benefit of $0	—	—		—	—		—		7		7
Comprehensive Income											598
Cash Dividends at $0.57 per share on Common Stock	—	—		—	—		(285)		—		(285)
Other	—	9		—	5		—		—		14
Balance as of June 30, 2023	534	$	5,054	(37)	$	(1,386)	$	11,900	$	(515)	$	15,053

Balance as of March 31, 2022	534	$	4,978	(37)	$	(1,336)	$	10,366	$	(410)	$	13,598
Net Income	—	—		—	—		131		—		131
Other Comprehensive Income (Loss), net of tax (expense) benefit of $29	—	—		—	—		—		(45)		(45)
Comprehensive Income											86
Cash Dividends at $0.54 per share on Common Stock	—	—		—	—		(270)		—		(270)
Payments for Share Repurchase Program	—	50		—	(50)		—		—		—
Other	—	10		—	4		—		—		14
Balance as of June 30, 2022	534	$	5,038	(37)	$	(1,382)	$	10,227	$	(455)	$	13,428



	Common Stock		Contributed Capital		Basis Adjustment		Retained Earnings		Accumulated Other Comprehensive Income (Loss)
											Total
Balance as of March 31, 2023	$	892	$	1,170	$	986	$	13,126	$	(4)	$	16,170
Net Income	—		—		—		336		—		336
Other Comprehensive Income (Loss), net of tax (expense) benefit of $0	—		—		—		—		—		—
Comprehensive Income											336

Balance as of June 30, 2023	$	892	$	1,170	$	986	$	13,462	$	(4)	$	16,506

Balance as of March 31, 2022	$	892	$	1,170	$	986	$	12,033	$	(2)	$	15,079
Net Income	—		—		—		305		—		305
Other Comprehensive Income (Loss), net of tax (expense) benefit of $1	—		—		—		—		(1)		(1)
Comprehensive Income											304


Balance as of June 30, 2022	$	892	$	1,170	$	986	$	12,338	$	(3)	$	15,383




	September 30, 2017			December 31, 2016
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Accounts Payable	$	499		$	539
Accounts Payable—Affiliated Companies	128			25
Derivative Contracts	7			8
Accrued Interest	43			20
Other	87			88
Total Current Liabilities	764			680
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	1,962			2,170
Asset Retirement Obligations	530			511
OPEB Costs	258			251
Derivative Contracts	1			3
Accrued Pension Costs	174			191
Long-Term Accrued Taxes	57			77
Other	123			129
Total Noncurrent Liabilities	3,105			3,332
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)
LONG-TERM DEBT	2,385			2,382
MEMBER’S EQUITY
Contributed Capital	2,214			2,214
Basis Adjustment	(986		)	(986		)
Retained Earnings	4,301			4,782
Accumulated Other Comprehensive Loss	(152		)	(211		)
Total Member’s Equity	5,377			5,799
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	11,631		$	12,193




	As of September 30, 2017
	Hope Creek			Salem			Support Facilities and Other (A)		Peach Bottom
	Millions
Assets
Materials and Supplies Inventory	$	85		$	81		$	—	$	41
Nuclear Production, net of Accumulated Depreciation	452			557			204		753
Nuclear Fuel In-Service, net of Accumulated Depreciation	120			94			—		109
Construction Work in Progress (including nuclear fuel)	216			130			9		92
Total Assets	$	873		$	862		$	213	$	995
Liability
Asset Retirement Obligation	$	148		$	162		$	—	$	164
Total Liabilities	$	148		$	162		$	—	$	164
Net Assets	$	725		$	700		$	213	$	831
NRC License Renewal Term	2046			2036/2040			—		2033/2034
% Owned	100		%	57		%	—		50		%




	Lease Receivables, Net of Non-Recourse Debt
Counterparties’ Credit Rating Standard & Poor’s (S&P) as of September 30, 2017
	As of September 30, 2017
	Millions
AA	$	15
BBB+ — BBB-	316
BB-	133
CCC-	82
Total	$	546




Asset	Location	Gross Investment		% Owned		Total MW	Fuel Type	Counterparties’ S&P Credit Ratings	Counterparty
		Millions
Powerton Station Units 5 and 6	IL	$	133	64	%	1,538	Coal	BB-	NRG Energy, Inc.
Joliet Station Units 7 and 8	IL	$	84	64	%	1,036	Gas	BB-	NRG Energy, Inc.
Keystone Station Units 1 and 2	PA	$	20	17	%	1,711	Coal	CCC-	REMA (A)
Conemaugh Station Units 1 and 2	PA	$	20	17	%	1,711	Coal	CCC-	REMA (A)
Shawville Station Units 1, 2, 3 and 4	PA	$	80	100	%	596	Gas	CCC-	REMA (A)




	As of December 31, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	705	$	263	$	(11	)	$	957
Debt Securities
Government	518		8		(6		)	520
Corporate	337		4		(4		)	337
Total Debt Securities	855		12		(10		)	857
Other Securities	44		—		—			44
Total NDT Available-for-Sale Securities (A)	$	1,604	$	275	$	(21	)	$	1,858




	Auction Year
	2014	2015	2016	2017
36-Month Terms Ending	May 2017	May 2018	May 2019	May 2020	(A)
Load (MW)	2,800	2,900	2,800	2,800
$ per MWh	$97.39	$99.54	$96.38	$90.78




Fuel Type	Power's Share of Commitments through 2021
	Millions
Nuclear Fuel
Uranium	$	257
Enrichment	$	328
Fabrication	$	178
Natural Gas	$	963
Coal	$	308




	As of September 30, 2017
	Power (A)									PSEG (A)		Consolidated
	Not Designated									Designated as Hedges
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total Power			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	352		$	(268	)	$	84		$	—	$	84
Noncurrent Assets	178			(116		)	62			—		62
Total Mark-to-Market Derivative Assets	$	530		$	(384	)	$	146		$	—	$	146
Derivative Contracts
Current Liabilities	$	(268	)	$	261		$	(7	)	$	—	$	(7	)
Noncurrent Liabilities	(110		)	109			(1		)	—		(1		)
Total Mark-to-Market Derivative (Liabilities)	$	(378	)	$	370		$	(8	)	$	—	$	(8	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	152		$	(14	)	$	138		$	—	$	138




Accumulated Other Comprehensive Income	Pre-Tax			After-Tax
	Millions
Balance as of December 31, 2015	$	—		$	—
Gain Recognized in AOCI	3			2
Less: Gain Reclassified into Income	—			—
Balance as of December 31, 2016	$	3		$	2
Gain Recognized in AOCI	1			—
Less: Gain Reclassified into Income	(2		)	(1		)
Balance as of September 30, 2017	$	2		$	1




Rating	Current Exposure		Collateral Held		Net Exposure		Number of Counterparties >10%	Net Exposure of Counterparties >10%
	Millions							Millions
Investment Grade	$	318	$	55	$	263	2	$	128	(A)
Non-Investment Grade	5		1		4		—	—
Total	$	323	$	56	$	267	2	$	128




	Quantitative Information About Level 3 Fair Value Measurements

								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	December 31, 2016					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contract	$	—	$	(5	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	—	$	(5	)
Power
Electricity	Electric Load Contracts	$	7	$	(1	)	Discounted Cash Flow	Historic Load Variability	0% to +10%
Gas (A)	Other	—		—
Total Power		$	7	$	(1	)
Total PSEG		$	7	$	(6	)




	Three Months Ended September 30, 2017
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1, 2017			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)		Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)			Balance as of September 30, 2017
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	6		$	3	$	—	$	—	$	(3	)	$	—		$	6
PSE&G
Net Derivative Assets (Liabilities)	$	—		$	—	$	—	$	—	$	—		$	—		$	—
Power
Net Derivative Assets (Liabilities)	$	6		$	3	$	—	$	—	$	(3	)	$	—		$	6

	Nine Months Ended September 30, 2017
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2017			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)		Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)			Balance as of September 30, 2017
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	1		$	29	$	5	$	—	$	(28	)	$	(1	)	$	6
PSE&G
Net Derivative Assets (Liabilities)	$	(5	)	$	—	$	5	$	—	$	—		$	—		$	—
Power
Net Derivative Assets (Liabilities)	$	6		$	29	$	—	$	—	$	(28	)	$	(1	)	$	6




	Three Months Ended September 30, 2016
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1, 2016			Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of September 30, 2016
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	5		$	8	$	(2	)	$	4	$	(4	)	$	—	$	11
PSE&G
Net Derivative Assets (Liabilities)	$	(2	)	$	—	$	(2	)	$	—	$	—		$	—	$	(4	)
Power
Net Derivative Assets (Liabilities)	$	7		$	8	$	—		$	4	$	(4	)	$	—	$	15

	Nine Months Ended September 30, 2016
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2016			Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of September 30, 2016

PSEG
Net Derivative Assets (Liabilities)	$	13		$	24	$	(6	)	$	4	$	(24	)	$	—	$	11
PSE&G
Net Derivative Assets (Liabilities)	$	2		$	—	$	(6	)	$	—	$	—		$	—	$	(4	)
Power
Net Derivative Assets (Liabilities)	$	11		$	24	$	—		$	4	$	(24	)	$	—	$	15




	As of				As of
	September 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A) (B)	$	1,896	$	1,891	$	1,195	$	1,185
PSE&G (B)	8,243		8,857		7,818		8,240
Power - Recourse Debt (B)	2,385		2,657		2,382		2,578
Total Long-Term Debt	$	12,524	$	13,405	$	11,395	$	12,003




PSEG	Other Comprehensive Income (Loss)
	Three Months Ended September 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of June 30, 2017	$	2		$	(386	)	$	158		$	(226	)
Other Comprehensive Income before Reclassifications	—			—			25			25
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(1		)	6			(8		)	(3		)
Net Current Period Other Comprehensive Income (Loss)	(1		)	6			17			22
Balance as of September 30, 2017	$	1		$	(380	)	$	175		$	(204	)

PSEG	Other Comprehensive Income (Loss)
	Three Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of June 30, 2016	$	1		$	(370	)	$	117		$	(252	)
Other Comprehensive Income before Reclassifications	1			—			26			27
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			9			(2		)	7
Net Current Period Other Comprehensive Income (Loss)	1			9			24			34
Balance as of September 30, 2016	$	2		$	(361	)	$	141		$	(218	)

PSEG	Other Comprehensive Income (Loss)
	Nine Months Ended September 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2016	$	2		$	(398	)	$	133		$	(263	)
Other Comprehensive Income before Reclassifications	—			—			78			78
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(1		)	18			(36		)	(19		)
Net Current Period Other Comprehensive Income (Loss)	(1		)	18			42			59
Balance as of September 30, 2017	$	1		$	(380	)	$	175		$	(204	)

PSEG	Other Comprehensive Income (Loss)
	Nine Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2015	$	—		$	(386	)	$	91		$	(295	)
Other Comprehensive Income before Reclassifications	2			—			44			46
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			25			6			31
Net Current Period Other Comprehensive Income (Loss)	2			25			50			77
Balance as of September 30, 2016	$	2		$	(361	)	$	141		$	(218	)




	Three Months Ended September 30,								Nine Months Ended September 30,
	2017				2016				2017				2016
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions):
Net Income	$	395	$	395	$	327	$	327	$	618	$	618	$	985	$	985
EPS Denominator (Millions):
Weighted Average Common Shares Outstanding	505		505		505		505		505		505		505		505
Effect of Stock Based Compensation Awards	—		2		—		3		—		2		—		3
Total Shares	505		507		505		508		505		507		505		508

EPS
Net Income	$	0.78	$	0.78	$	0.65	$	0.64	$	1.22	$	1.22	$	1.95	$	1.94




	PSE&G		Power			Other (A)			Eliminations (B)			Consolidated Total
	Millions
Three Months Ended September 30, 2017
Total Operating Revenues	$	1,509	$	873		$	135		$	(254	)	$	2,263
Net Income (Loss)	246		136			13			—			395
Gross Additions to Long-Lived Assets	729		327			9			—			1,065
Nine Months Ended September 30, 2017
Operating Revenues	$	4,689	$	3,086		$	334		$	(1,121	)	$	6,988
Net Income (Loss)	753		(131		)	(4		)	—			618
Gross Additions to Long-Lived Assets	2,118		903			25			—			3,046
Three Months Ended September 30, 2016
Total Operating Revenues	$	1,684	$	1,075		$	7		$	(316	)	$	2,450
Net Income (Loss)	255		139			(67		)	—			327
Gross Additions to Long-Lived Assets	680		325			9			—			1,014
Nine Months Ended September 30, 2016
Operating Revenues	$	4,746	$	3,102		$	256		$	(1,133	)	$	6,971
Net Income (Loss)	696		320			(31		)	—			985
Gross Additions to Long-Lived Assets	2,035		923			27			—			2,985
As of September 30, 2017
Total Assets	$	27,802	$	11,631		$	2,288		$	(564	)	$	41,157
Investments in Equity Method Subsidiaries	$	—	$	90		$	—		$	—		$	90
As of December 31, 2016
Total Assets	$	26,288	$	12,193		$	2,373		$	(784	)	$	40,070
Investments in Equity Method Subsidiaries	$	—	$	102		$	—		$	—		$	102




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended September 30, 2017
Operating Revenues	$	—		$	856		$	46		$	(29	)	$	873
Operating Expenses	2			643			44			(29		)	660
Operating Income (Loss)	(2		)	213			2			—			213
Equity Earnings (Losses) of Subsidiaries	143			(3		)	3			(140		)	3
Other Income	24			58			(2		)	(37		)	43
Other Deductions	—			(8		)	—			—			(8		)
Other-Than-Temporary Impairments	—			(5		)	—			—			(5		)
Interest Expense	(32		)	(12		)	(5		)	37			(12		)
Income Tax Benefit (Expense)	3			(103		)	2			—			(98		)
Net Income (Loss)	$	136		$	140		$	—		$	(140	)	$	136
Comprehensive Income (Loss)	$	156		$	154		$	—		$	(154	)	$	156
Nine Months Ended September 30, 2017
Operating Revenues	$	—		$	3,036		$	145		$	(95	)	$	3,086
Operating Expenses	4			3,315			139			(95		)	3,363
Operating Income (Loss)	(4		)	(279		)	6			—			(277		)
Equity Earnings (Losses) of Subsidiaries	(111		)	(8		)	11			119			11
Other Income	71			155			—			(99		)	127
Other Deductions	(1		)	(21		)	—			—			(22		)
Other-Than-Temporary Impairments	—			(9		)	—			—			(9		)
Interest Expense	(96		)	(30		)	(14		)	99			(41		)
Income Tax Benefit (Expense)	10			68			2			—			80
Net Income (Loss)	$	(131	)	$	(124	)	$	5		$	119		$	(131	)
Comprehensive Income (Loss)	$	(72	)	$	(80	)	$	5		$	75		$	(72	)
Nine Months Ended September 30, 2017
Net Cash Provided By (Used In) Operating Activities	$	(55	)	$	1,159		$	142		$	3		$	1,249
Net Cash Provided By (Used In) Investing Activities	$	738		$	(289	)	$	(343	)	$	(990	)	$	(884	)
Net Cash Provided By (Used In) Financing Activities	$	(683	)	$	(869	)	$	211		$	987		$	(354	)




	MTM VaR
	Three Months Ended September 30, 2017		Year Ended December 31, 2016
	Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	8	$	26
Average for the Period	$	7	$	16
High	$	9	$	32
Low	$	5	$	10
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	13	$	40
Average for the Period	$	11	$	25
High	$	15	$	51
Low	$	8	$	16




Three Months Ended September 30, 2017	Total Number of Shares Purchased	Average Price Paid per Share
July 1 - July 31	—	$	—
August 1 - August 31	135,277	$	45.25
September 1- September 30	—	$	—